**UNITEDSTATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

 

### **FORM 10-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, 2006**

 

**OR**

 

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

**FOR THE TRANSITION PERIOD FROM                     TO                     **

 

**Commissionfile number 1-10389**

 

### **WESTERN GAS RESOURCES,INC.**

(Exact Name ofRegistrant as Specified in Its Charter)

 

| **Delaware**                                        | ** ** | **84-1127613**       |
|-----------------------------------------------------|------------|----------------------|
| (State or Other  Jurisdiction of                    |       | (I.R.S. Employer     |
| Incorporation or  Organization)                     |       | Identification  No.) |
|                                                |       |                 |
| **1099 18th  Street, Suite 1200, Denver, Colorado** |       | **80202**            |
| (Address of  Principal Executive Offices)           |       | (Zip Code)           |

 

**(303)452-5603**

Registrant’sTelephone Number, Including Area Code

 

**NoChanges**

(Former Name,Former Address and Former Fiscal Year, if Changed Since Last Report).

 

Indicate by check markwhether 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 markwhether the registrant is a large accelerated filer, an accelerated filer, or anon-accelerated filer. See definition of “accelerated filer and largeaccelerated filer” in Rule 12b-2 of the Exchange Act. (Check one): LargeAccelerated Filer ý

Accelerated Filer o             Non-Accelerated Filer o

 

Indicate by check markwhether the registrant is a shell company (as defined in Rule 12b-2 of theExchange Act). Yes o No ý

 

On May 4, 2006, therewere 76,008,737 shares of the registrant’s common stock outstanding.

 

 

----

 

**Western Gas Resources, Inc.**

 

**Form 10-Q**

**Table ofContents**

 
| PART I - Financial Information |                                                                                                |
|--------------------------------|-----------------------------------------------------------------------------------------------------|
|                           |                                                                                                |   |
| Item 1.                        | Financial Statements                                                                                |   |
|                           |                                                                                                |   |
|                           | Consolidated Balance Sheet - March  31, 2006 and December 31, 2005                                  |   |
|                           |                                                                                                |   |
|                           | Consolidated Statement of  Cash Flows - Three Months Ended March 31, 2006 and 2005                  |   |
|                           |                                                                                                |   |
|                           | Consolidated Statement of  Operations - Three Months Ended March 31, 2006 and 2005                  |   |
|                           |                                                                                                |   |
|                           | Consolidated Statement of  Changes in Stockholders’ Equity - Three Months Ended March 31, 2006 |   |
|                           |                                                                                                |   |
|                           | 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

----

 

**PARTI - FINANCIAL INFORMATION**

 

**ITEM 1.**                             FINANCIAL STATEMENTS

** **

WESTERNGAS RESOURCES, INC.

CONSOLIDATED BALANCE SHEET

(Unaudited)

(Dollars inthousands, except share data)

 
| ** **                                                                                                            | ** ** | **March 31,** | ** ** | **December 31,** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------|------------|---------------|------------|------------------|------------|
| ** **                                                                                                            | ** ** | **2006**      | ** ** | **2005**         | ** ** |
| ASSETS                                                                                                                |       |          |       |             |       |
| Current assets:                                                                                                       |       |          |       |             |       |
| Cash and cash  equivalents                                                                                            |       | $             | 7,580      |             | $          | 27,198 |   |
| Trade accounts  receivable, net                                                                                       |       | 313,784       |       | 413,004          |       |
| Margin deposits                                                                                                       |       | 5,486         |       | 31,217           |       |
| Inventory                                                                                                             |       | 93,690        |       | 136,968          |       |
| Assets from  price risk management activities                                                                         |       | 46,508        |       | 48,988           |       |
| Deferred tax  asset                                                                                                   |       | —        |       | 4,808            |       |
| Other                                                                                                                 |       | 14,264        |       | 14,010           |       |
| Total current  assets                                                                                                 |       | 481,312       |       | 676,193          |       |
|                                                                                                                  |       |          |       |             |       |
| Property and equipment:                                                                                               |       |          |       |             |       |
| Gas gathering,  processing and transportation                                                                         |       | 1,320,588     |       | 1,290,278        |       |
| Oil and gas  properties and equipment (successful efforts method)                                                     |       | 798,724       |       | 666,306          |       |
| Construction in  progress                                                                                             |       | 395,440       |       | 286,641          |       |
|                                                                                                                  |       | 2,514,752     |       | 2,243,225        |       |
| Less:  Accumulated depreciation, depletion and amortization                                                           |       | (716,879      | )          | (684,904         | )          |
|                                                                                                                  |       |          |       |             |       |
| Total property  and equipment, net                                                                                    |       | 1,797,873     |       | 1,558,321        |       |
|                                                                                                                  |       |          |       |             |       |
| Other assets:                                                                                                         |       |          |       |             |       |
| Gas purchase  contracts (net of accumulated amortization of $42,988 and $42,583,  respectively)                       |       | 30,920        |       | 32,071           |       |
| Assets from  price risk management activities                                                                         |       | 8,437         |       | 5,495            |       |
| Investments in  joint ventures                                                                                        |       | 39,249        |       | 36,791           |       |
| Other                                                                                                                 |       | 27,627        |       | 25,763           |       |
|                                                                                                                  |       |          |       |             |       |
| Total other assets                                                                                                    |       | 106,233       |       | 100,120          |       |
|                                                                                                                  |       |          |       |             |       |
| TOTAL ASSETS                                                                                                          |       | $             | 2,385,418  |             | $          | 2,334,634 |   |
|                                                                                                                  |       |          |       |             |       |
| LIABILITIES AND  STOCKHOLDERS’ EQUITY                                                                            |       |          |       |             |       |
| Current liabilities:                                                                                                  |       |          |       |             |       |
| Accounts payable                                                                                                      |       | $             | 378,068    |             | $          | 463,113 |   |
| Accrued expenses                                                                                                      |       | 73,363        |       | 106,542          |       |
| Income tax  payable                                                                                                   |       | 11,032        |       | —           |       |
| Liabilities from  price risk management activities                                                                    |       | 4,592         |       | 34,343           |       |
| Deferred tax  liability                                                                                               |       | 6,509         |       | —           |       |
| Dividends  payable                                                                                                    |       | 5,698         |       | 5,660            |       |
| Total current  liabilities                                                                                            |       | 479,262       |       | 609,658          |       |
|                                                                                                                  |       |          |       |             |       |
| Long-term debt                                                                                                        |       | 515,000       |       | 430,000          |       |
| Liabilities from price risk management activities                                                                     |       | 155           |       | —           |       |
| Other long-term liabilities                                                                                           |       | 65,970        |       | 66,427           |       |
| Deferred income taxes, net                                                                                            |       | 337,916       |       | 325,090          |       |
|                                                                                                                  |       |          |       |             |       |
| Total liabilities                                                                                                     |       | 1,398,303     |       | 1,431,175        |       |
|                                                                                                                  |       |          |       |             |       |
| Stockholders’ equity:                                                                                            |       |          |       |             |       |
| Common stock, par  value $0.10; 100,000,000 shares authorized; 75,906,185 and 75,375,134 shares  issued, respectively |       | 7,594         |       | 7,565            |       |
| Treasury stock,  at cost; 50,032 common shares in treasury                                                            |       | (788          | )          | (788             | )          |
| Deferred  compensation                                                                                                |       | —        |       | (9,244           | )          |
| Additional  paid-in capital                                                                                           |       | 431,521       |       | 429,007          |       |
| Retained  earnings                                                                                                    |       | 528,023       |       | 471,860          |       |
| Accumulated  other comprehensive income                                                                               |       | 20,765        |       | 5,059            |       |
|                                                                                                                  |       |          |       |             |       |
| Total  stockholders’ equity                                                                                      |       | 987,115       |       | 903,459          |       |
|                                                                                                                  |       |          |       |             |       |
| TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY                                                                       |       | $             | 2,385,418  |             | $          | 2,334,634 |   |

 

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

 

3

----

 

WESTERN GASRESOURCES, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

(Dollars inthousands)

 
| ** **                                                                              | ** ** | **Three Months Ended** | ** ** |
|-----------------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                              | ** ** | **March 31,**               | ** ** |
| ** **                                                                              | ** ** | **2006**                         | ** ** | **2005** | ** ** |
|                                                                                    |       |                             |       |   |   |
| Reconciliation of net income to net cash provided by  operating activities:             |       |                             |       |   |   |
| Net income                                                                              |       | $                                | 61,862     |   | $ | 19,706 |   |
| Add income items that do not affect operating cash  flows:                              |       |                             |       |   |   |
| Depreciation,  depletion and amortization                                               |       | 35,362                           |       | 29,078 |   |
| Loss on sale of  assets                                                                 |       | 1,044                            |       | 28 |   |
| Deferred income  taxes                                                                  |       | 22,045                           |       | 4,078 |   |
| Excess tax  benefits from share-based payment awards                                    |       | (1,484                           | )          | — |   |
| Non-cash change  in fair value of derivatives                                           |       | (4,182                           | )          | 28,677 |   |
| Compensation  expense from restricted stock and stock options                           |       | 4,651                            |       | 273 |   |
| Other non-cash  items, net                                                              |       | (3,630                           | )          | (1,220 | ) |
|                                                                                    |       |                             |       |   |   |
| Adjustments to working capital to arrive at net cash  provided by operating activities: |       |                             |       |   |   |
| Decrease in  trade accounts receivable                                                  |       | 99,176                           |       | 21,557 |   |
| (Increase)  decrease in margin deposits                                                 |       | 15,841                           |       | (7,649 | ) |
| Decrease in  product inventory                                                          |       | 43,818                           |       | 29,654 |   |
| (Increase) in  other current assets                                                     |       | (6,122                           | )          | (994 | ) |
| (Increase)  decrease in other assets and liabilities, net                               |       | 719                              |       | (674 | ) |
| (Decrease) in  accounts payable                                                         |       | (70,087                          | )          | (10,603 | ) |
| Increase  (decrease) in accrued expenses                                                |       | (11,003                          | )          | 5,485 |   |
|                                                                                    |       |                             |       |   |   |
| Net cash provided by operating activities                                               |       | 188,010                          |       | 117,396 |   |
|                                                                                    |       |                             |       |   |   |
| Cash flows from investing activities:                                                   |       |                             |       |   |   |
|                                                                                    |       |                             |       |   |   |
| Purchases of  property and equipment, including acquisitions                            |       | (265,051                         | )          | (115,332 | ) |
| Distributions  from equity investees                                                    |       | —                           |       | 324 |   |
| Proceeds from  the disposition of property and equipment                                |       | 1,152                            |       | 767 |   |
|                                                                                    |       |                             |       |   |   |
| Net cash used in investing activities                                                   |       | (263,899                         | )          | (114,241 | ) |
|                                                                                    |       |                             |       |   |   |
| Cash flows from financing activities:                                                   |       |                             |       |   |   |
|                                                                                    |       |                             |       |   |   |
| Net proceeds  from exercise of common stock options                                     |       | 4,806                            |       | 2,307 |   |
| Excess tax  benefits from share-based payment awards                                    |       | 1,484                            |       | — |   |
| Change in  outstanding checks                                                           |       | (29,344                          | )          | (4,283 | ) |
| Borrowings on  revolving credit facility                                                |       | 957,100                          |       | 807,065 |   |
| Payments on  revolving credit facility                                                  |       | (872,100                         | )          | (803,165 | ) |
| Borrowings on  long-term debt                                                           |       | —                           |       | 25,000 |   |
| Payments on  long-term debt                                                             |       | —                           |       | (25,000 | ) |
| Debt issue costs  paid                                                                  |       | (14                              | )          | (40 | ) |
| Dividends paid                                                                          |       | (5,661                           | )          | (3,704 | ) |
|                                                                                    |       |                             |       |   |   |
| Net cash provided by (used in) financing activities                                     |       | 56,271                           |       | (1,820 | ) |
|                                                                                    |       |                             |       |   |   |
| Net increase (decrease) in cash and cash equivalents                                    |       | (19,618                          | )          | 1,335 |   |
|                                                                                    |       |                             |       |   |   |
| Cash and cash equivalents at beginning of period                                        |       | 27,198                           |       | 390 |   |
|                                                                                    |       |                             |       |   |   |
| Cash and cash equivalents at end of period                                              |       | $                                | 7,580      |   | $ | 1,725 |   |

 

Theaccompanying notes are an integral part of the consolidated financialstatements.

 

4

----

 

WESTERN GAS RESOURCES, INC.CONSOLIDATED STATEMENT OF OPERATIONS(Unaudited)(Dollars in thousands, except share and per share amounts)

 
| ** **                                                               | ** ** | **Three Months Ended** | ** ** |
|--------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                               | ** ** | **March 31,**               | ** ** |
| ** **                                                               | ** ** | **2006**                         | ** ** | **2005** | ** ** |
| Revenues:                                                                |       |                             |       |   |   |
| Sale of gas                                                              |       | $                                | 771,661    |   | $ | 696,219 |   |
| Sale of natural  gas liquids                                             |       | 167,416                          |       | 132,969 |   |
| Gathering,  processing and transportation                                |       | 26,700                           |       | 23,880 |   |
| Price risk  management activities                                        |       | 20,980                           |       | (20,248 | ) |
| Other                                                                    |       | 2,324                            |       | 1,287 |   |
| Total revenues                                                           |       | 989,081                          |       | 834,107 |   |
|                                                                     |       |                             |       |   |   |
| Costs and  expenses:                                                     |       |                             |       |   |   |
| Product  purchases                                                       |       | 776,132                          |       | 707,354 |   |
| Plant and  transportation operating expense                              |       | 32,216                           |       | 27,699 |   |
| Oil and gas  exploration and production expense                          |       | 28,518                           |       | 24,896 |   |
| Depreciation,  depletion and amortization                                |       | 35,362                           |       | 29,078 |   |
| Selling and  administrative expense                                      |       | 18,804                           |       | 12,532 |   |
| Loss on sale of  assets                                                  |       | 1,044                            |       | 28 |   |
| Earnings from  equity investments                                        |       | (2,374                           | )          | (2,134 | ) |
| Interest expense                                                         |       | 3,185                            |       | 3,520 |   |
| Total costs and  expenses                                                |       | 892,887                          |       | 802,973 |   |
| Income before  income taxes                                              |       | 96,194                           |       | 31,134 |   |
| Provision for  income taxes:                                             |       |                             |       |   |   |
| Current                                                                  |       | 12,287                           |       | 7,350 |   |
| Deferred                                                                 |       | 22,045                           |       | 4,078 |   |
| Total provision  for income taxes                                        |       | 34,332                           |       | 11,428 |   |
|                                                                     |       |                             |       |   |   |
| Net income                                                               |       | $                                | 61,862     |   | $ | 19,706 |   |
|                                                                     |       |                             |       |   |   |
| Earnings per  share of common stock                                      |       | $                                | 0.82       |   | $ | 0.27 |   |
|                                                                     |       |                             |       |   |   |
| Weighted average  shares of common stock outstanding                     |       | 75,079,330                       |       | 74,148,269 |   |
|                                                                     |       |                             |       |   |   |
| Earnings per  share of common stock - assuming dilution                  |       | $                                | 0.81       |   | $ | 0.26 |   |
|                                                                     |       |                             |       |   |   |
| Weighted average  shares of common stock outstanding - assuming dilution |       | 76,063,490                       |       | 75,559,318 |   |

 

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

 

5

----

 

WESTERN GAS RESOURCES, INC.CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY(Unaudited)(Dollars in thousands, except share amounts)

 
| ** **                                             | ** ** | ** **         | ** ** | ** **           | ** ** | ** ** | ** ** | ** **   | ** ** | ** **       | ** ** | ** **     | ** ** | ** **   | ** ** | **Accumulated**          | ** ** | ** **        | ** ** |
|--------------------------------------------------------|------------|--------------------|------------|----------------------|------------|------------|------------|--------------|------------|------------------|------------|----------------|------------|--------------|------------|--------------------------|------------|-------------------|------------|
| ** **                                             | ** ** | ** **         | ** ** | **Shares**           | ** ** | ** ** | ** ** | ** **   | ** ** | ** **       | ** ** | ** **     | ** ** | ** **   | ** ** | **Other**                | ** ** | **Total**         | ** ** |
| ** **                                             | ** ** | **Shares**         | ** ** | **of Common**   | ** ** | ** ** | ** ** | ** **   | ** ** | ** **       | ** ** | **Additional** | ** ** | ** **   | ** ** | **Comprehensive**        | ** ** | **Stock-**        | ** ** |
| ** **                                             | ** ** | **of Common** | ** ** | **Stock**            | ** ** | **Common** | ** ** | **Treasury** | ** ** | **Deferred**     | ** ** | **Paid-In**    | ** ** | **Retained** | ** ** | **Income (Loss)**   | ** ** | **holders’** | ** ** |
| ** **                                             | ** ** | **Stock**          | ** ** | **in Treasury** | ** ** | **Stock**  | ** ** | **Stock**    | ** ** | **Compensation** | ** ** | **Capital**    | ** ** | **Earnings** | ** ** | **Net of Tax** | ** ** | **Equity**        | ** ** |
| Balance at  December 31, 2005                          |       | 75,375,134         |       | 50,032               |       | $          | 7,565      |         | $          | (788             | )          | $              | (9,244     | )            | $          | 429,007                  |       | $                 | 471,860    |   | $ | 5,059 |   | $ | 903,459 |   |
| Comprehensive  income:                                 |       |               |       |                 |       |       |       |         |       |             |       |           |       |         |       |                     |       |              |       |
| Net income, first  quarter of 2006                     |       | —             |       | —               |       | —     |       | —       |       | —           |       | —         |       | 61,862       |       | —                   |       | 61,862            |       |
| Translation  adjustments                               |       | —             |       | —               |       | —     |       | —       |       | —           |       | —         |       | —       |       | (1,274                   | )          | (1,274            | )          |
| Other  comprehensive income                            |       |               |       |                 |       |       |       |         |       |             |       |           |       |         |       |                     |       |              |       |
| From equity  investees                                 |       | —             |       | —               |       | —     |       | —       |       | —           |       | —         |       | —       |       | 84                       |       | 84                |       |
| Reclassification  adjustment for settled contracts     |       | —             |       | —               |       | —     |       | —       |       | —           |       | —         |       | —       |       | (3,811                   | )          | (3,811            | )          |
| Changes in fair  value of outstanding hedge positions  |       | —             |       | —               |       | —     |       | —       |       | —           |       | —         |       | —       |       | 18,063                   |       | 18,063            |       |
| Fair value of new  hedge positions                     |       | —             |       | —               |       | —     |       | —       |       | —           |       | —         |       | —       |       | 2,644                    |       | 2,644             |       |
| Change in  accumulated derivative comprehensive income |       | —             |       | —               |       | —     |       | —       |       | —           |       | —         |       | —       |       | 16,896                   |       | 16,896            |       |
| Total  comprehensive income, net of tax                |       | —             |       | —               |       | —     |       | —       |       | —           |       | —         |       | —       |       | —                   |       | 77,568            |       |
| Stock options  exercised                               |       | 251,108            |       | —               |       | 29         |       | —       |       | —           |       | 4,777          |       | —       |       | —                   |       | 4,806             |       |
| Compensation  expense from common stock options        |       | —             |       | —               |       | —     |       | —       |       | —           |       | 3,258          |       | —       |       | —                   |       | 3,258             |       |
| Excess tax  benefit related to stock options exercised |       | —             |       | —               |       | —     |       | —       |       | —           |       | 2,330          |       | —       |       | —                   |       | 2,330             |       |
| Effect of change  in accounting principle              |       | —             |       | —               |       | —     |       | —       |       | 9,244            |       | (9,244         | )          | —       |       | —                   |       | —            |       |
| Compensation  expense from restricted stock            |       | 279,943            |       | —               |       | —     |       | —       |       |             |       | 1,393          |       | —       |       | —                   |       | 1,393             |       |
| Dividends  declared on common stock                    |       | —             |       | —               |       | —     |       | —       |       | —           |       | —         |       | (5,699       | )          | —                   |       | (5,699            | )          |
|                                                   |       |               |       |                 |       |       |       |         |       |             |       |           |       |         |       |                     |       |              |       |
| Balance at March  31, 2006                             |       | 75,906,185         |       | 50,032               |       | $          | 7,594      |         | $          | (788             | )          | $              | —     |         | $          | 431,521                  |       | $                 | 528,023    |   | $ | 20,765 |   | $ | 987,115 |   |

 

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

 

6

----

 

WESTERN GAS RESOURCES,INC.

NOTES TOCONSOLIDATED FINANCIAL STATEMENTS 

(Unaudited)

 

***NOTE 1 – GENERAL***

 

We have prepared the accompanying unaudited interimconsolidated financial statements under the rules and regulations of theSecurities and Exchange Commission, or SEC. As provided by such rules and regulations, we have condensed or omittedcertain information and notes normally included in annual financial statementsprepared in conformity with accounting principles generally accepted in theUnited States of America.

 

The interim consolidated financial statementspresented herein should be read in conjunction with the Consolidated FinancialStatements and Notes thereto included in our Annual Report on Form 10-K for theyear ended December 31, 2005.  Referenceis also made to our 2005 Form 10-K for definitions of terms used in thisquarterly report on Form 10-Q.  Theinterim Consolidated Financial Statements as of March 31, 2006 and for thethree-month periods ended March 31, 2006 and 2005 included herein are unauditedbut reflect, in the opinion of management, all adjustments (which include onlynormal recurring adjustments) necessary to fairly state the results for suchperiods.  The results of operations forthe three months ended March 31, 2006 are not necessarily indicative of theresults of operations expected for the year ended December 31, 2006.

 

***EarningsPer Share of Common Stock.***   Earnings per share of common stock arecomputed by dividing net income by the weighted average shares of common stockoutstanding.  Earnings per share ofcommon stock - assuming dilution is computed by dividing net income by theweighted average shares of common stock outstanding as adjusted for potentialcommon shares.  

 

The following table presents the dividends declared byus on our common stock (dollars in thousands, except per share amounts):

 
| ** **                                   | ** ** | **Quarter Ended March 31,** | ** ** |
|----------------------------------------------|------------|-----------------------------|------------|
| ** **                                   | ** ** | **2006**                    | ** ** | **2005** | ** ** |
| Total dividends declared                     |       | $                           | 5,699      |   | $ | 3,710 |   |
| Dividends declared per share of common stock |       | $                           | 0.075      |   | $ | 0.05 |   |

 

Common stock options granted are potential commonshares with the exception of the grants in the quarter ended March 31, 2006,which are anti-dilutive.  The followingis a reconciliation of the weighted average shares of common stock outstandingto the weighted average common shares outstanding – assuming dilution.  

 
| ** **                                                               | ** ** | **Quarter Ended March 31,** | ** ** |
|--------------------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                               | ** ** | **2006**                    | ** ** | **2005** | ** ** |
| Weighted average shares of common stock outstanding                      |       | 75,079,330                  |       | 74,148,269 |   |
| Potential common shares from common stock options                        |       | 984,161                     |       | 1,411,049 |   |
| Weighted average shares of common stock outstanding  - assuming dilution |       | 76,063,490                  |       | 75,559,318 |   |

 

The calculation of fully diluted earnings per sharereflects potential common shares, if dilutive. 

 

***AccumulatedOther Comprehensive Income.***  Included in Accumulated other comprehensiveincome at March 31, 2006 were unrealized gains of $19.5 million, which is netof $11.2 million of deferred taxes, from the fair value of derivativesdesignated as cash flow hedges and unrealized losses of $1.3 million, which isnet of $0.8 million of deferred taxes, as a result of cumulative foreigncurrency translation adjustments.  

 

The gains currently reflected in Accumulated othercomprehensive income from the fair value of derivatives designated as cash flowhedges will be reclassified to earnings as the hedged gas or NGLs aresold.  Based on the prices for ourproducts on March 31, 2006, approximately $19.5 million of gains in Accumulatedother comprehensive income will be reclassified to earnings, of which $16.3million will be reclassified in the remainder of 2006.  

 

***RevenueRecognition.***  Inthe Gas Gathering, Processing and Treating segment, we recognize revenue forour services at the time the service is performed.  We record revenue from our gas and NGLmarketing activities, including sales of our equity production, upon transferof title.  In accordance with EITF 03-11,“Reporting Realized Gains and Losses on Derivative Instruments That are Subjectto FASB Statement No. 133, Accounting for Derivative Instruments and HedgingActivities, and Not Held for Trading Purposes as Defined in Issue No. 02-3”,

 

7

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we record revenue on our physical gas and NGL marketing activities on agross basis versus sales net of purchases basis because we obtain title to allthe gas and NGLs that we buy including third-party purchases, bear the risk ofloss and credit exposure on these transactions, and it is our intention uponentering these contracts to take physical delivery of the product.  Gas imbalances on our production areaccounted for using the sales method. Gas imbalances on our production at March 31, 2006 and 2005 wereimmaterial.  For our marketing activitieswe utilize mark-to-market accounting for our derivatives.  In the Transportation segment, we realizerevenue on a monthly basis from firm capacity contracts under which the shipperpays for transport capacity whether or not the capacity is used and frominterruptible contracts where a fee is charged based upon volumes received intothe pipeline.   

 

***SupplementaryCash Flow Information.*** Interest paid was $6.0 million and $6.1 million for the quarters endedMarch 31, 2006 and 2005, respectively.  Atotal of $472,000 was paid in income taxes in the quarter ended March 31,2006.  No income taxes were paid in thequarter ending March 31, 2005.  Assetretirement obligation assets and liabilities of $1.9 million and $1.6 million wererecorded for the quarters ended March 31, 2006 and 2005, respectively.  The asset retirement and associatedobligations are non-cash transactions for presentation on the ConsolidatedStatement of Cash Flows.

 

***PropertyAcquisition.***  InMarch 2006, we acquired certain coal bed methane, or CBM, properties andrelated gathering assets in the Big George fairway of the Powder River Basin ofWyoming from an undisclosed seller for approximately $136.7 million beforeadjustments.  This acquisition was fundedwith amounts available under our revolving credit facility.  The purchase price includes the drillingrights on approximately 40,000 gross and net acres and 110 drilled wells.  These properties had no production in March2006 as approximately 70 of the drilled wells are currently dewatering and theremaining 40 wells are awaiting hookup. The adjusted purchase price of $138.6 million at closing is included inthe Consolidated Balance Sheet at March 31, 2006 and is summarized as follows(amounts in thousands):

 
| Gas gathering,  processing and transportation |   | $ | 1,770   |   |
|-----------------------------------------------|--------|---|---------|--------|
| Oil and gas properties and equipment          |   | $ | 136,778 |   |
| Other long-term liabilities                   |   | $ |    |   |

 

***NOTE 2 - DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES***

 

A net gain was recognized in earnings through Sale ofgas and Sale of natural gas liquids during the three months ended March 31,2006 from hedging activities of $8.5 million. A net gain was recognized in earnings through Sale of gas and Sale ofnatural gas liquids during the three months ended March 31, 2005 from hedgingactivities of $487,000.  

 

***NOTE 3 – ADOPTION OF SFAS 123(R)***

 

On January 1, 2006, we adopted Statement of FinancialAccounting Standards No. 123 (revised 2004), “Share-Based Payment”, or SFAS123(R), which requires the measurement and recognition of compensation expensefor all share-based payment awards (including stock options) made to employeesand directors based on estimated fair values. SFAS 123(R) supersedes our previous accounting under AccountingPrinciples Board Opinion No. 25, “Accounting for Stock Issued to Employees”, orAPB 25, for periods beginning in fiscal 2006.  In March 2005, the SEC issued Staff AccountingBulletin No. 107, or SAB 107, relating to SFAS 123(R).  We considered the guidance of SAB 107 in ouradoption of SFAS 123(R).

 

We adopted SFAS 123(R) using the modified prospectivetransition method, which requires the application of the accounting standard asof January 1, 2006.  In accordance withthe modified prospective transition method, our Consolidated FinancialStatements for prior periods are not restated to reflect, and do not include,any impact of SFAS 123(R).  We did notmodify any outstanding stock options in anticipation of the adoption of SFAS123(R).   The effect of the change inaccounting principle resulting from the adoption of SFAS 123(R) was recognizedin our financial statements through the elimination of previously recognizeddeferred compensation costs, with offsetting amounts recorded in the Additionalpaid-in capital account within Stockholders’ equity.

 

Stock-based compensation expense recognized under SFAS123(R) for the three months ended March 31, 2006 related to employee stockoptions, including compensation from our February 2006 grants is as presentedin the following table.  

 

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| **(Amounts in thousands, except  per share amounts)**                     | ** ** | **Quarter ended   March 31, 2006** | ** ** |
|---------------------------------------------------------------------------|------------|------------------------------------|------------|
| Incremental stock-based compensation expense  recognized through earnings |       | $                                  | 2,842      |   |
| Related deferred income tax benefit                                       |       | (539                               | )          |
| Decrease in net income                                                    |       | 2,303                              |       |
| Decrease in earnings per share of common stock                            |       | 0.03                               |       |
| Decrease in earnings per share of common stock –  assuming dilution  |       | 0.03                               |       |
| Stock-based compensation expense capitalized                              |       | $                                  | 574        |   |

 

SFAS 123(R) requires usto estimate the fair value of stock options on the date of grant using anoption-pricing model. The value of the portion of the award that is ultimatelyexpected to vest is recognized as expense over the requisite service periods inour Consolidated Statement of Operations. Prior to the adoption of SFAS 123(R),we accounted for stock-based awards to employees and directors using theintrinsic value method in accordance with APB 25 as then allowed underStatement of Financial Accounting Standards No. 123, “Accounting forStock-Based Compensation”, or SFAS 123. Under the intrinsic value method, withthe exception of the options granted under the Chief Executive Officer andPresident’s Plan and our restricted stock, no stock-based compensation expensehad been recognized in our Consolidated Statement of Operations, because theexercise price of our stock options granted to employees and directors equaledthe fair market value of the underlying stock at the date of grant.

 

Stock-based compensationexpense to be recognized is based on the value of those share-based paymentawards that are ultimately expected to vest during the period. Stock-basedcompensation expense recognized in our Consolidated Statement of Operations forthe first quarter of 2006 includes compensation expense for share-based paymentawards granted prior to, but not yet vested, as of January 1, 2006. Thisexpense is based on the grant date fair value estimated in accordance with thepro forma provisions of SFAS 123. Compensation expense for the share-basedpayment awards granted subsequent to December 31, 2005 was based on the grantdate fair value estimated in accordance with the provisions of SFAS 123(R). Inconjunction with the adoption of SFAS 123(R), we continued our method ofattributing the value of stock-based compensation using the straight-linesingle option method. As stock-based compensation expense recognized in theConsolidated Statement of Operations for the first quarter of 2006 is based onawards ultimately expected to vest, it is reduced for estimated forfeitures. SFAS123(R) requires forfeitures to be estimated at the time of grant and revised,if necessary, in subsequent periods if actual forfeitures differ from thoseestimates. At March 31, 2006, the compensation expense related to non-vestedawards to be recognized in future periods totals $26.2 million. The weightedaverage period over which this expense is expected to be recognized is 2.2years.

 

In accordance with theadoption of SFAS 123(R), we continue to use the Black-Scholes option pricingmodel for the valuation of share-based awards. Our determination of fair valueof share-based payment awards on the date of grant using the Black-Scholesmodel is affected by our stock price as well as assumptions regardingvariables, including, but not limited to, our expected stock price volatilityover the term of the awards, and actual and projected employee stock optionexercise behaviors. In our estimate of the fair value of the share-basedpayment awards, we utilize historical volatility of our common stock over 250weeks. In our opinion, the historical volatility and the Black-Scholes modelprovide an appropriate measure of the fair value of our employee stock options.

 

On November 10, 2005, theFinancial Accounting Standards Board, issued FASB Staff Position, or FSP, No.123(R)-3, “Transition Election Related to Accounting for Tax Effects ofShare-Based Payment Awards.”  This FSPallows us to take up to one year from the later of our initial adoption of SFAS123(R) or the effective date of the FSP to evaluate the available transitionalternative related to the accounting for the tax effects of share-basedpayment awards that are partially or fully-vested as of the adoption date. Wehave not adopted the alternative method during the first quarter of 2006 andmay adopt it in a subsequent quarter.

 

***NOTE 4 – SHARE BASED COMPENSATION***

 

A description of ourshare based compensation plans in effect at March 31, 2006 is as follows:

 

***1999 Non-Employee Directors Stock Option Plan.***EffectiveMarch 1999, the board of directors adopted a 1999 Non-Employee Directors’ StockOption Plan, or 1999 Directors Plan, that authorized the granting of options topurchase 30,000 shares of our common stock. During 1999, the board approvedoptions grants covering 30,000 shares to several board members. Under thisplan, each of these options becomes exercisable as to 33 1/3% of the sharescovered by it on each anniversary from the date of grant. This plan terminateson the earlier of March 12, 2009 or the date on which all options granted underthe plan have been exercised in full.

 

***1997and 1999 Stock Option Plans.***The 1997 Stock Option Plan,or 1997 Plan, and the 1999 Stock Option Plan, or 1999 Plan, became effective onMay 21, 1997, and May 21, 1999, respectively, after approvals by ourstockholders. Each plan is intended to be an incentive stock option plan inaccordance with the provisions of Section 

 

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422 of the InternalRevenue Code of 1986, as amended. We reserved 2,000,000 shares of common stockfor issuance upon exercise of options under the 1997 Plan and 1,500,000 sharesof common stock for issuance upon exercise of options under the 1999 Plan. The1997 Plan and the 1999 Plan will terminate on the later of May 21, 2007 and May21, 2009, respectively, or the date on which all the respective options grantedunder each of the plans have expired or been exercised in full. Althoughoptions covering 745,204 shares are available to be granted under the 1997Plan, no further options will be granted under this plan.

 

***Chief Executive Officer and President’sPlan (“CEO Plan”).***Pursuant to the Employment Agreement,dated October 15, 2001, and the Stock Option Agreement, dated as of November 1,2001, between us and Peter A. Dea, our Chief Executive Officer and President,non-qualified stock options were granted for the purchase of 600,000 shares ofour common stock. The exercise price of the options was equal to $2.50 belowthe closing price per share on the effective date of the Employment Agreement. Thestock options are subject to the conditions of the Agreements and vestedequally over four years. The difference between the closing price on theeffective date and the exercise price was amortized over four years ascompensation expense. This option plan will terminate on the earlier of October15, 2010 or the date on which all options granted under the plan have beenexercised in full. On August 1, 2005,we entered into a new employment agreement with Mr. Dea, which due to recentchanges in the tax laws required that he exercise, on or before March 15, 2006,options to purchase 150,000 shares of our common stock, which vested onNovember 15, 2005.

 

***2002 Non-Employee Directors Stock Option Plan.***EffectiveMay 2002, our stockholders approved the 2002 Non-Employee Directors’ StockOption Plan, or 2002 Directors Plan, that authorized the granting of options topurchase 220,000 shares of our common stock. The 2002 Directors Plan provides for a three-year vesting schedule whilethe non-employee director serves on our board. Under this plan, a newly electednon-employee director will be granted options to acquire 10,000 shares ofcommon stock as of the date of election. The 2002 Directors Plan also providesfor an annual grant on the date of our annual meeting to each non-employeedirector options to acquire 4,000 shares of common stock. The purchase price ofthe stock under each option shall be the fair market value of the stock at thetime such option is granted. The 2002 Directors Plan requires the non-employeedirector to exercise the option at the earlier of ten years from the date ofthe plan or within five years of the date each portion vests, or such optionsexpire. The non-employee director’s right to exercise options under the 2002Directors Plan is subject to continuous service since the grant was made. Ifthe non-employee director dies or becomes disabled (within the meaning of the2002 Directors Plan) or a change of control occurs, then all the optionsgranted to the non-employee director shall become 100% exercisable. The2002 Directors Plan will terminate on the later of May 17, 2012 or the date onwhich all options granted under the plan have expired or been exercised infull.

 

***2002 Stock Option Plan.***Effective May 2002, our stockholders approved the 2002 Stock IncentivePlan, or 2002 Plan, that authorized the granting of options to purchase2,500,000 shares of our common stock. No employee may be granted options toacquire more than 250,000 shares of common stock in any fiscal year. The 2002Plan requires the employee to exercise the option at the earlier of ten yearsfrom the date of the 2002 Plan or within five years of the date each portionvests, or such options expire. The employee’s right to exercise options underthe 2002 Plan is subject to continuous employment since the grant was made. Ifthe employee dies, becomes disabled (within the meaning of the 2002 Plan) or achange of control occurs, then all the options granted to the employee shallbecome 100% exercisable. The 2002 Plan will terminate on the laterof May 17, 2012 or the date on which all options granted under the plan haveexpired or been exercised in full.

 

***2005 Stock Option Plan.***Effective May 2005, our stockholders approved the 2005 Stock IncentivePlan, or 2005 Plan, that authorized the granting of options to purchase2,500,000 shares of our common stock and the granting of 1,500,000 shares ofrestricted common stock. No employee may be granted options to acquire morethan 250,000 shares of common stock or 150,000 shares of restricted commonstock in any fiscal year. The 2005 Plan requires the employee to exercise theoptions at the earlier of five years of the date each portion vests or sevenyears from the date the options are granted, or such options expire. Theemployee’s right to exercise options under the 2005 Plan is subject tocontinuous employment since the grant was made. If a change of control occurs,then all of the options granted to the employee shall become 100% exercisableand all restricted shares become vested. The 2005Plan will terminate on the later of May 6, 2015 or the date on which alloptions granted under the plan have expired or been exercised in full.

 

Under each of the 1997, 1999, 2002 and 2005 plans(including the non-employee director plans), our board of directors determinesand designates from time to time our employees to whomoptions or restricted shares are to be granted. If any option terminates orexpires prior to being exercised, the shares relating to such option arereleased and may be subject to re-issuance pursuant to a new option. Thepurchase price of the stock under each option shall be the average closingprice for the ten days prior to the grant. Under the 1997, 1999, 2002 and 2005Plans, our 

 

10

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board of directors hasthe authority to set the vesting schedule based on service from 20% per year to33 1/3% per year. Under each of the plans, the employee must exercise theoption within five years of the date each portion vests.

 

Inthe first quarter of 2006, we granted to our employees options to purchaseapproximately 686,000 shares of our common stock at the market based on theaverage closing price for the ten days prior to grant, and approximately280,000 shares of restricted common stock to our employees. In the firstquarter of 2005, we granted options to purchase 83,000 shares of our commonstock at the market based on the average closing price for the ten days priorto grant. We did not grant any restricted common stock during the first quarterof 2005. 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 and on disqualifying dispositions ofqualified stock options. For the quarters ended March 31, 2006 and 2005, werecognized a tax benefit from our stock options of $2.3 million.

 

Thefollowing is a summary of the options to purchaseour common stock granted and the weighted average fair value per share ofthe options granted during thequarters ended March 31, 2006 and 2005, respectively.

 
| ** **                             | ** ** | **Quarter Ended March 31,** | ** ** |
|----------------------------------------|------------|-----------------------------|------------|
| ** **                             | ** ** | **2006**                    | ** ** | **2005** | ** ** |
| 2002 Plan                              | ** ** | ** **                  | ** ** | ** ** | ** ** |
| Options granted                        |       | 6,200                       |       | 83,000 |   |
| Weighted average fair value  per share |       | $                           | 15.06      |   | $ | 15.65 |   |
| 2005 Plan                              |       |                        |       |   |   |
| Options granted                        |       | 660,026                     |       | — |   |
| Weighted average fair value  per share |       | $                           | 19.17      |   | — |   |
| 2002 Directors Plan                    |       |                        |       |   |   |
| Options granted                        |       | 20,000                      |       | — |   |
| Weighted average fair value  per share |       | $                           | 19.45      |   | — |   |
|                                        |            |                             |            |  |  |  |  |

 

Duringthe quarter ended March 31, 2006, the valuesfor the options granted were estimated using the Black-Scholes option-pricingmodel with the following assumptions:

 
| ** **                     | ** ** | **2002 Plan** | ** ** | **2005 Plan** | ** ** | **2002 Directors Plan** | ** ** |
|--------------------------------|------------|---------------|------------|---------------|------------|-------------------------|------------|
| Risk-free interest rate        |       | 4.90          | %          | 5.11          | %          | 5.11                    | %          |
| Expected life (in years)       |       | 4.5           |       | 4.33          |       | 4.5                     |       |
| Expected volatility            |       | 32            | %          | 32            | %          | 32                      | %          |
| Expected dividends (quarterly) |       | $             | 0.075      |          | $          | 0.075                   |       | $ | 0.075 |   |
|                                |            |               |            |               |            |                         |            |  |  |  |

 

Thefollowing table summarizes the number of stock options exercisable andavailable for grant under our benefit plans at March 31, 2006:

 
| ** **               | ** ** | **Per  Share  Price Range** | ** **       | **1997  Plan** | ** ** | **1999  Plan** | ** ** | **1999  Directors  Plan** | ** ** | **CEO  Plan** | ** ** | **2002  Plan** | ** ** | **2002  Directors  Plan** | ** ** | **2005  Plan** | ** ** |
|--------------------------|------------|-----------------------------|------------------|----------------|------------|----------------|------------|---------------------------|------------|---------------|------------|----------------|------------|---------------------------|------------|----------------|------------|
| **Exercisable:**         |       |                        |             |           |       |           |       |                      |       |          |       |           |       |                      |       |           |       |
| March 31, 2006           |       | $                           | 0.01–5.00   |           | 1,202      |           | —     |                      | 2,600      |          | —     |           | —     |                      | —     |           | —     |   |
|                     |       | $                           | 5.01–10.00  |           | 2,800      |           | —     |                      | —     |          | —     |           | —     |                      | —     |           | —     |   |
|                     |       | $                           | 10.01–15.00 |           | —     |           | 11,002     |                      | —     |          | 450,000    |           | —     |                      | —     |           | —     |   |
|                     |       | $                           | 15.01–20.00 |           | —     |           | 345,232    |                      | —     |          | —     |           | 299,010    |                      | 46,667     |           | —     |   |
|                     |       | $                           | 20.01–25.00 |           | —     |           | —     |                      | —     |          | —     |           | 1,112      |                      | —     |           | —     |   |
|                     |       | $                           | 25.01–30.00 |           | —     |           | 34,115     |                      | —     |          | —     |           | 230,550    |                      | 9,333      |           | —     |   |
|                     |       | $                           | 30.01–35.00 |           | —     |           | —     |                      | —     |          | —     |           | 25,556     |                      | —     |           | —     |   |
|                     |       | $                           | 35.01–40.00 |           | —     |           | —     |                      | —     |          | —     |           | 1,668      |                      | —     |           | —     |   |
|                     |       | TOTAL                       |             | 4,002          |       | 390,349        |       | 2,600                     |       | 450,000       |       | 557,896        |       | 56,000                    |       | —         |       |
|                     |       |                        |             |           |       |           |       |                      |       |          |       |           |       |                      |       |           |       |
| **Available for Grant:** | ** ** | ** **                  | ** **       | ** **     | ** ** | ** **     | ** ** | ** **                | ** ** | ** **    | ** ** | ** **     | ** ** | ** **                | ** ** | ** **     | ** ** |
| March 31, 2006           |       | —                      |             | 745,204        |       | 18,089         |       | —                    |       | —        |       | 40,438         |       | 72,000                    |       | 1,104,234      |       |

 

Thefollowing table summarizes the stock option activity related to optionsoutstanding under our benefit plans during the quarter ended March 31, 2006:

 
| ** **                                           | ** ** | **Per  Share Price Range** | ** **  | **1997  Plan** | ** ** | **1999  Plan** | ** ** | **1999  Directors  Plan** | ** ** | **CEO  Plan** | ** ** | **2002  Plan** | ** ** | **2002  Directors  Plan** | ** ** | **2005  Plan** | ** ** |
|------------------------------------------------------|------------|----------------------------|-------------|----------------|------------|----------------|------------|---------------------------|------------|---------------|------------|----------------|------------|---------------------------|------------|----------------|------------|
| Balance at 12/31/05                                  |       |                       |        | 6,002          |       | 550,815        |       | 6,600                     |       | 495,000       |       | 1,817,154      |       | 112,000                   |       | 744,726        |       |
| Granted                                              |       | $                          | 43.43-48.51 |           | —     |           | —     |                      | —     |          | —     |           | 6,200      |                      | 20,000     |           | 660,026    |   |
| Exercised                                            |       | $                          | 2.76-35.71  |           | (2,000     | )              | (38,773    | )                         | (4,000     | )             | (45,000    | )              | (161,335   | )                         | —     |           | —     |   |
| Forfeited or  expired                                |       | $                          | 16.48-50.05 |           | —     |           | (1,001     | )                         | —     |          | —     |           | (16,137    | )                         | —     |           | (8,986     | ) |
| Balance at 3/31/06                                   |       |                       |        | 4,002          |       | 511,041        |       | 2,600                     |       | 450,000       |       | 1,645,882      |       | 132,000                   |       | 1,395,766      |       |
| Weighted-average  remaining contractual life (years) |       |                       |        | 2.0            |       | 5.0            |       | 1.0                       |       | 3.6           |       | 5.3            |       | 5.0                       |       | 6.2            |       |

 

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The following table summarizes the weighted averageoption exercise price information under our benefit plans during the quarterended March 31, 2006:

 
| ** **            | ** ** | **1997  Plan** | ** ** | **1999  Plan** | ** ** | **1999  Directors  Plan** | ** ** | **CEO  Plan** | ** ** | **2002  Plan** | ** ** | **2002  Directors  Plan** | ** ** | **2005  Plan** | ** ** |
|-----------------------|------------|----------------|------------|----------------|------------|---------------------------|------------|---------------|------------|----------------|------------|---------------------------|------------|----------------|------------|
| Balance at 12/31/05   |       | $              | 5.11       |           | $          | 19.32                     |       | $             | 2.76       |           | $          | 12.51                     |       | $              | 24.31      |   | $ | 24.99 |   | $ | 31.86 |   |
| Granted               |       | —         |       | —         |       | —                    |       | —        |       | 47.35          |       | 43.43                     |       | 43.43          |       |
| Exercised             |       | (5.82          | )          | (17.40         | )          | (2.76                     | )          | (12.51        | )          | (20.28         | )          | —                    |       | —         |       |
| Forfeited or  expired |       | —         |       | (28.35         | )          | —                    |       | —        |       | (23.79         | )          | —                    |       | (34.67         | )          |
| Balance at 3/31/06    |       | $              | 4.76       |           | $          | 19.45                     |       | $             | 2.76       |           | $          | 12.51                     |       | $              | 24.80      |   | $ | 27.79 |   | $ | 37.31 |   |

 

The total aggregateintrinsic value of options exercised in the quarter ended March 31, 2006 wasapproximately $7.2 million. The total aggregate intrinsic value of exercisableoptions at March 31, 2006 was approximately $45.5 million and the totalaggregate intrinsic value of outstanding options at March 31, 2006 wasapproximately $87.7 million.

 

The following tablesummarizes the status of the shares of outstanding restricted stock as of March31, 2006 and changes during the quarter ended March 31, 2006:

 
| ** **                                                            | ** ** | **2005  Plan** | ** ** |
|-----------------------------------------------------------------------|------------|----------------|------------|
| Balance at 12/31/05                                                   |       | 377,565        |       |
| Granted                                                               |       | 279,943        |       |
| Exercised                                                             |       | —         |       |
| Forfeited or  expired                                                 |       | (8,609         | )          |
| Balance at 3/31/06                                                    |       | 648,899        |       |
| Weighted-average  grant date fair value per share of restricted stock |       | $              | 39.49      |   |
| Weighted-average remaining contractual life (years)                   |       | 1.5            |       |
|                                                                       |            |                |            |  |

 

Asdiscussed in Note 3 above, prior to January 1, 2006, we were not required torecord compensation expense for share-based payment awards.Ifwe had recorded compensation expense in the first quarter of 2005 for grantsunder our stock-based compensation plans consistent with SFAS 123 (R), our NetIncome, Earnings per share of common stock and Earnings per share of commonstock - assuming dilution would approximate the pro forma amounts below(dollars in thousands, except per share amounts):

 
| ** **                                                                                                                                     | ** ** | **Quarter Ended  March 31, 2005** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------------------|------------|
| ** **                                                                                                                                     | ** ** | **As Reported**                   | ** ** | **Pro Forma** | ** ** |
| Net income                                                                                                                                     |       | $                                 | 19,706     |   | $ | 18,027 |   |
| Earnings per share of common stock                                                                                                             |       | 0.27                              |       | 0.24 |   |
| Earnings per share of common stock – assuming  dilution                                                                                   |       | 0.26                              |       | 0.24 |   |
| Stock-based  employee compensation cost, net of related tax effects, included in net  income                                                   |       | 178                               |       | — |   |
| 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 |   |
|                                                                                                                                                |            |                                   |            |  |  |  |  |  |

 

***NOTE5 - SEGMENT REPORTING***

 

Weoperate in four principal business segments, as follows: Gathering, Processingand Treating; Exploration and Production; Marketing; and Transportation. Managementseparately monitors these segments for performance against our internalforecast, and these segments are consistent with our internal financialreporting package. These segments have been identified based upon the differingproducts and services, regulatory environment and the expertise required forthese operations.

 

***Gathering, Processing and Treating.***Inthe Gathering, Processing and Treating segment, collectively with the Marketingand Transportation segments referred to as the midstream operations, we connectproducers’ wells (including those of our Exploration and Production segment) toour gathering systems for delivery of natural gas to 

 

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our processing or treating plants, process the natural gas to extractNGLs and treat the natural gas in order to meet pipeline specifications. Insome areas, where no processing is required, we gather and compress producers’gas and deliver it to pipelines for further delivery to market. Except forvolumes taken in kind by our producers, the Marketing segment sells the gas andNGLs extracted at most of our facilities. In this segment, we recognize revenuefor our services at the time the service is performed.

 

Substantially all gasflowing through our gathering, processing and treating facilities is suppliedunder three types of contracts providing for the purchase, gathering, treatingor processing of natural gas for periods ranging from one month to 20 years orin some cases for the life of the oil and gas lease. Approximately 77% of ourplant facilities’ gross margin, or revenues at the plant less productpurchases, or 38% of our plant facilities’ throughput volume for the month ofMarch 2006, was under percentage-of-proceeds agreements where we are typicallyresponsible for the marketing of the gas and NGLs. Under these agreements, wepay producers a specified percentage of the net proceeds received from the saleof the gas and the NGLs. Revenue is recognized under these contracts when thegas or NGLs are sold and the related product purchases are recorded as apercentage of the sale of the product.

 

Approximately 21% of ourplant facilities’ gross margin, or 54% of our plant facilities’ throughputvolume, for the month of March 2006 was under contracts that are primarilyfee-based from which we receive a set fee for each Mcf of gas gathered and/orprocessed. This type of contract provides us with a steady revenue stream thatis not dependent on commodity prices, except to the extent that low prices maycause a producer to delay drilling or shut in production. Revenue is recognizedunder these contracts when the related services are rendered.

 

Approximately 2% of ourplant facilities’ gross margin, or 8% of our plant facilities’ throughputvolume, for the month of March 2006 was under contracts with keepwholearrangements or wellhead purchase contracts. Under the keepwhole contracts, weretain the NGLs recovered by the processing facility and keep the producerswhole by returning to the producers at the tailgate of the plant an amount ofgas equal on a Btu basis to the natural gas received at the plant inlet. Thekeepwhole component of the contracts permits us to benefit when the value ofthe NGLs is greater as a liquid than as a portion of the residue gas stream.However, we are adversely affected when the value of the NGLs is lower as aliquid than as a portion of the residue gas stream. Revenue is recognized underthese contracts when the product is sold.

 

***Exploration and Production.***Theactivities of the Exploration and Production segment, also referred to asupstream operations, include the exploration and development of gas propertiesin the Rocky Mountain area, including those where our gathering and/orprocessing 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 gas and a proportionalshare of transportation charges. Also included in this segment are our Canadianexploration and development operations, which are conducted through our whollyowned subsidiary Western Gas Resources Canada Company and which are immaterialfor separate presentation.

 

Exploratorylease rentals and geological and geophysical costs are charged to expense asincurred. Exploratory drilling costs are capitalized when incurred pending thedetermination of whether a well has found proved reserves. The determination ofwhether a well has found proved reserves is based on a process that relies oninterpretations of available geological, geophysical, and engineering data. Ifan exploratory well is determined to be unsuccessful, the capitalized drillingcosts will be charged to expense in the period the determination is made. If anexploratory well requires a major capital expenditure before production canbegin, the cost of drilling the exploratory well will continue to be carried asan asset pending determination of whether proved reserves have been found onlyas long as: i) the well has found a sufficient quantity of reserves to justifyits completion as a producing well if the required capital expenditure is made,and ii) drilling of additional exploratory wells is under way or firmly plannedfor the near future. If the drilling of additional exploratory wells in thearea is not under way or firmly planned, or if the well has not found acommercially producible quantity of reserves, the exploratory well is assumedto be impaired, and its costs are charged to expense.

 

The following table reflects the net changes incapitalized exploratory well costs during the three months ended March 31, 2006(dollars in thousands).

 

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| ** **                                                                                            | ** ** | **Three Months Ended  March 31, 2006** | ** ** |
|-------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------|------------|
| Beginning  balance at December 31, 2005                                                               |       | $                                                          | 101,796    |   |
| Additions to  capitalized exploratory well costs pending the determination of proved  reserves        |       | 42,027                                                     |       |
| Reclassifications  to wells, facilities, and equipment based on the determination of proved  reserves |       | (2,045                                                     | )          |
| Capitalized  exploratory well costs charged to expense                                                |       | —                                                     |       |
| Ending balance  at March 31, 2006                                                                     |       | $                                                          | 141,778    |   |

 

Periodend capitalized exploratory well costs (000s) and number of gross wells atMarch 31, 2006 are as follows:

 
| ** **                                                                | ** ** | **Exploratory  Well Costs** | ** ** | **Number  of wells** | ** ** |
|---------------------------------------------------------------------------|------------|----------------------------------|------------|---------------------------|------------|
| Exploratory well  costs capitalized for a period of one year or less      |       | $                                | 93,556     |                      | 582        |   |
| Exploratory well  costs capitalized for a period of greater than one year |       | 48,222                           |       | 618                       |       |
| Total  exploratory well costs capitalized at March 31, 2006               |       | $                                | 141,778    |                      | 1,200      |   |

 

Substantiallyall of our exploratory wells that have been capitalized for a period greaterthan one year are located in the Powder River Basin. In this basin, we drillwells into various coal seams. After these wells are completed, lease-operatingcosts are incurred. In order to produce gas from the coal seams, a period ofdewatering lasting from a few to thirty-six months, or in some cases longer, isrequired prior to obtaining sufficient gas production to justify capitalexpenditures for compression and gathering, and to classify the reserves asproved. In order to accelerate the dewatering time, we drill additionalexploratory wells in these areas.

 

***Marketing.***OurMarketing segment markets gas and NGLs extracted at our gathering, processingand treating facilities and produced from our Exploration and Productionsegment and buys and sells gas and NGLs in the United States and Canada fromand to a variety of customers. In this segment, revenues for sales of productare recognized at the time the gas or NGLs are delivered to the customer andtitle passes. Revenues in this segment are sensitive to changes in the marketprices of the underlying commodities. The marketing of products purchased fromthird-parties typically results in low operating margins relative to the salesprice. We sell our products under agreements with varying terms and conditionsin order to match seasonal and other changes in demand. Also included in thissegment are our Canadian marketing operations, which are conducted through ourwholly owned subsidiary WGR Canada, Inc. and which are immaterial for separatepresentation.

 

***Transportation.***TheTransportation segment reflects the operations of our MIGC, Inc. and MGTC, Inc.pipelines. The revenue presented in this segment is derived from transportationof gas for our Marketing segment and third parties. In this segment, we realizerevenue on a monthly basis from firm capacity contracts under which the shipperpays for transport capacity whether or not the capacity is used and frominterruptible contracts where a fee is charged based upon volumes received intothe pipeline. The Transportation segment’s capacity contracts range in durationfrom one month to five years.

 

***Segment Information.*** The followingtables set forth our segment information as of and for the quarters ended March31, 2006 and 2005 (dollars in thousands). Due to our integrated operations, theuse of allocations in the determination of business segment information isnecessary. Inter-segment revenues are valued at prices comparable to those ofunaffiliated customers. 

 

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**Quarter Ended March 31, 2006:**

 
| ** **                                         | ** ** | **Gas Gathering  and   Processing** | ** ** | **Exploration  and  Production** | ** ** | **Marketing** | ** ** | **Transportation** | ** ** | **Corporate** | ** ** | **Eliminating  Entries** | ** ** | **Total** | ** ** |
|----------------------------------------------------|------------|-----------------------------------------------|------------|----------------------------------|------------|---------------|------------|--------------------|------------|---------------|------------|--------------------------|------------|-----------|------------|
| Revenues from  unaffiliated customers:             |       |                                          |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Sale of gas and  NGLs                              |       | $                                             | 298        |                             | $          | 2,911         |       | $                  | 926,347    |          | $          | 1,002                    |       | $         | —     |   | $ | — |   | $ | 930,558 |   |
| Equity hedges                                      |       | 1,101                                         |       | 7,419                            |       | —        |       | —             |       | —        |       | —                   |       | 8,520     |       |
| Gathering,  processing and transportation revenue  |       | 24,862                                        |       | —                           |       | —        |       | 1,837              |       | —        |       | —                   |       | 26,699    |       |
| Total revenues  from unaffiliated customers        |       | 26,261                                        |       | 10,330                           |       | 926,347       |       | 2,839              |       | —        |       | —                   |       | 965,777   |       |
|                                               |       |                                          |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Inter-segment  revenues                            |       | 332,699                                       |       | 101,525                          |       | 26,818        |       | 3,341              |       | 115           |       | (464,498                 | )          | —    |       |
| Price risk  management activities                  |       | —                                        |       | (3,582                           | )          | 24,562        |       | —             |       | —        |       | —                   |       | 20,980    |       |
| Interest income  and Other, net                    |       | 1,642                                         |       | 95                               |       | 3             |       | —             |       | 17,658        |       | (17,074                  | )          | 2,324     |       |
| Total revenues                                     |       | 360,602                                       |       | 108,368                          |       | 977,730       |       | 6,180              |       | 17,773        |       | (481,572                 | )          | 989,081   |       |
|                                               |       |                                          |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Product  purchases and operating expenses          |       | 306,620                                       |       | 40,355                           |       | 952,473       |       | 2,135              |       | 117           |       | (464,834                 | )          | 836,866   |       |
| (Earnings) from  equity investments                |       | (2,374                                        | )          | —                           |       | —        |       | —             |       | —        |       | —                   |       | (2,374    | )          |
| Segment  operating profit                          |       | 56,356                                        |       | 68,013                           |       | 25,257        |       | 4,045              |       | 17,656        |       | (16,738                  | )          | 154,589   |       |
|                                               |       |                                          |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Depreciation,  depletion and Amortization          |       | 13,603                                        |       | 19,135                           |       | 2             |       | 464                |       | 2,158         |       | —                   |       | 35,362    |       |
| Selling and  administrative expense                |       | —                                        |       | —                           |       | —        |       | —             |       | 18,813        |       | (9                       | )          | 18,804    |       |
| (Gain) loss from  sale of assets                   |       | (2                                            | )          | 785                              |       | —        |       | 265                |       | (4            | )          | —                   |       | 1,044     |       |
| Interest expense                                   |       | —                                        |       | —                           |       | 430           |       | (312               | )          | 20,141        |       | (17,074                  | )          | 3,185     |       |
| Income before  income taxes                        |       | $                                             | 42,755     |                             | $          | 48,093        |       | $                  | 24,825     |          | $          | 3,628                    |       | $         | (23,452    | ) | $ | 345 |   | 96,194 |   |
|                                               |       |                                          |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Identifiable  assets:                              |       |                                          |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Property and  equipment and other allocated assets |       | $                                             | 895,916    |                             | $          | 850,573       |       | $                  | 193,826    |          | $          | 84,249                   |       | $         | 405,423    |   | $ | (83,818 | ) | $ | 2,346,169 |   |
| Equity  investments                                |       | 39,249                                        |       | —                           |       | —        |       | 1,205              |       | 1,051,755     |       | (1,052,960               | )          | 39,249    |       |
| Total  identifiable assets                         |       | $                                             | 935,165    |                             | $          | 850,573       |       | $                  | 193,826    |          | $          | 85,454                   |       | $         | 1,457,178  |   | $ | (1,136,778 | ) | $ | 2,385,418 |   |

 

**QuarterEnded March 31, 2005:**

 
| ** **                                          | ** ** | **Gas Gathering  and  Processing** | ** ** | **Exploration  and  Production** | ** ** | **Marketing** | ** ** | **Transportation** | ** ** | **Corporate** | ** ** | **Eliminating  Entries** | ** ** | **Total** | ** ** |
|-----------------------------------------------------|------------|-----------------------------------------|------------|----------------------------------|------------|---------------|------------|--------------------|------------|---------------|------------|--------------------------|------------|-----------|------------|
| Revenues from  unaffiliated  customers:             |       |                                    |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Sale of gas and  NGLs                               |       | $                                       | (178       | )                                | $          | 4,035         |       | $                  | 824,099    |          | $          | 745                      |       | $         | —     |   | $ | — |   | $ | 828,701 |   |
| Equity hedges                                       |       | (739                                    | )          | 1,226                            |       | —        |       | —             |       | —        |       | —                   |       | 487       |       |
| 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                                     | )          | —                           |       | (20,161       | )          | —             |       | —        |       | —                   |       | (20,248   | )          |
| Interest income  and Other, net                     |       | 1,105                                   |       | 6                                |       | —        |       | —             |       | 9,682         |       | (9,506                   | )          | 1,287     |       |
| Total revenues                                      |       | 298,247                                 |       | 74,373                           |       | 821,642       |       | 5,937              |       | 9,692         |       | (375,784                 | )          | 834,107   |       |
|                                                |       |                                    |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Product  purchases and operating expenses           |       | 248,092                                 |       | 35,421                           |       | 840,045       |       | 2,670              |       | —        |       | (366,279                 | )          | 759,949   |       |
| (Earnings) from  equity investments                 |       | (2,134                                  | )          | —                           |       | —        |       | —             |       | —        |       | —                   |       | (2,134    | )          |
| Segment  operating profit                           |       | 52,289                                  |       | 38,952                           |       | (18,403       | )          | 3,267              |       | 9,692         |       | (9,505                   | )          | 76,292    |       |
|                                                |       |                                    |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Depreciation,  depletion and amortization           |       | 11,279                                  |       | 15,629                           |       | 35            |       | 403                |       | 1,732         |       | —                   |       | 29,078    |       |
| Selling and  administrative expense                 |       | —                                  |       | —                           |       | —        |       | —             |       | 12,542        |       | (10                      | )          | 12,532    |       |
| (Gain) loss from  sale of assets                    |       | 31                                      |       | —                           |       | —        |       | (3                 | )          | —        |       | —                   |       | 28        |       |
| Interest expense                                    |       | 5                                       |       | 1                                |       | 2             |       | (154               | )          | 13,172        |       | (9,506                   | )          | 3,520     |       |
| Income before  income taxes                         |       | $                                       | 40,974     |                             | $          | 23,322        |       | $                  | (18,440    | )             | $          | 3,021                    |       | $         | (17,754    | ) | $ | 11 |   | $ | 31,134 |   |
|                                                |       |                                    |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Identifiable assets:                                |       |                                    |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Property and  equipment and other allocated assets  |       | $                                       | 717,521    |                             | $          | 522,394       |       | $                  | 116,164    |          | $          | 44,822                   |       | $         | 488,061    |   | $ | (98,095 | ) | $ | 1,830,867 |   |
| Equity investments                                  |       | 36,108                                  |       | —                           |       | —        |       | 1,071              |       | 757,071       |       | (758,142                 | )          | 36,108    |       |
| Total identifiable assets                           |       | $                                       | 753,629    |                             | $          | 522,394       |       | $                  | 116,164    |          | $          | 85,893                   |       | $         | 1,245,132  |   | $ | (856,237 | ) | $ | 1,866,975 |   |

 

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***NOTE 6 - LEGAL******PROCEEDINGS***

 

***Doyle and Margaret M. Hartman, et al. v. Questar Explorationand Production Company et al. In the District Court of Sublette County,Wyoming, Civil Action No. 2006-6843.***On March 31, 2006,the plaintiffs filed a complaint against a group of ten defendants, includingour subsidiary Lance Oil & Gas Company, Inc. The plaintiffs claim that theyhold a five percent net profits interest, which they allege was created in 1954and burdened certain oil and gas leases in the original federal Pinedale Unitin the Pinedale Anticline. The relief sought by the plaintiffs includes adeclaration that they hold a valid, continuing net profits interest applicableto certain identified leases, enforcement of the net profits interest,compensatory damages, an accounting of the status of the net profits interest,and interest and penalties under the Wyoming Royalty Payment Act.

 

***UnitedStates of America and ex rel. Jack J. Grynberg v. Western Gas Resources, Inc.,et al., United States District Court, District of Colorado, Civil Action No.97-D-1427.***We, along with over 300 other natural gascompanies, are defendants in litigation filed on September 30, 1997, in 72 separateactions filed by Mr. Grynberg on behalf of the federal government. Theallegations made by Mr. Grynberg are that established gas measurement androyalty calculation practices improperly deprived the federal government ofappropriate natural gas royalties and violate 31U.S.C. 3729(a)(7) of the FalseClaims Act. The cases have been consolidated to the United States DistrictCourt for the District of Wyoming. Discovery on the jurisdictional issues isbeing completed to determine if this matter qualifies as a qui tam, or class,action. The defendants’ joint Motion to Dismiss was argued before a specialmaster on March 17 and 18, 2005 and, as a result thereof, the special masterhas recommended to the court that claims against several of the defendants,including Western, be dismissed. The recommendation is pending before thecourt.

 

***Price,et al. v. Gas Pipelines, Western Gas Resources, Inc., et al., District Court,Stevens County, Kansas, Case No. 99-C-30.***We are adefendant in litigation filed on September 23, 1999, along with numerous othernatural gas companies, in which Mr. Price is claiming an under measurement ofgas and Btu volumes throughout the country. We, along with other natural gas companies,filed a motion to dismiss for failure to state a claim. The court denied thesemotions to dismiss. The court denied plaintiff’s motion for certification as aclass and, in the third quarter of 2003, the plaintiff amended and refiled forcertification as a class. On May 12, 2003, Mr. Price filed a further claim, *Will Price et al v. Western Gas Resources, Inc. etal., District Court, Stevens County, Kansas, Case No. 03C23*,relating to certain matters previously removed from the foregoing action.

 

***In re: Western States Wholesale Natural Gas AntitrustLitigation, J.P. Morgan Trust Company, National Association, in its Capacity asTrustee of FLI Liquidating Trust v. The Williams Companies, Inc., et al.,United States District Court, District of Nevada, MDL 1566 CV-S-03-1431-PMP.***OnOctober 17, 2005, the plaintiff, in its capacity as the liquidating trustee ofthe successor in interest to Farmland Industries, Inc., filed an amendedcomplaint, joining us and other defendants to this action, originally filed inthe District Court of Wyandotte County, Kansas. The defendants removed the caseto the U.S. District Court for the District of Kansas, following which theJudicial Panel on Multi District Litigation entered a transfer ordercentralizing the action in the U.S. District Court for the District of Nevadafor coordinated and consolidated pretrial proceedings. On April 21, 2006, theplaintiff’s motion to remand to Kansas state court was denied. The complaintclaims that the defendants violated the Kansas Restraint of Trade Act byreporting allegedly “misleading or knowingly inaccurate reports concerningtrade information” to trade publications that compile and publish indices ofnatural gas prices for natural gas trading hubs throughout the United States. Thecomplaint asserts that these alleged activities had the effect of increasingprices charged by the defendants for natural gas and preventing full and freecompetition. The plaintiff seeks to recover damages in the amount of the fullconsideration of its purchases of natural gas during the time period fromJanuary 1, 2000 through December 31, 2001, together with its costs oflitigation including attorney’s fees.

 

***Learjet, Inc., Cross Oil Refining & Marketing, Inc.Topeka Unified School District 501, on Behalf of Themselves and All OtherSimilarly Situated Direct Purchasers of Natural Gas in the State of Kansas v.Oneok, Inc. et al, In the District Court of Wyandotte County, Kansas, CivilAction No. 05-CV-1500.***On November 4, 2005, theplaintiffs, on behalf of themselves and all others similarly situated, filed anamended Petition for Damages, joining us and other defendants to this action.The Petition claims that the defendants violated the Kansas Restraint of TradeAct by reporting allegedly “misleading or knowingly inaccurate reportsconcerning trade information” to 

 

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trade publications that compile and publish indices of natural gasprices for natural gas trading hubs throughout the United States. The complaintasserts that the allegedly anticompetitive effect of the defendant’s actionswas to artificially inflate the prices paid by the plaintiffs for natural gas.The plaintiffs are bringing the action as a class action on behalf of allpersons and entities in Kansas who made direct purchases of natural gas, fortheir own use and or consumption, during the time period from January 1, 2000through October 31, 2002. The plaintiffs are seeking judgment for the fullconsideration of their purchases of natural gas purchased during such timeperiod, together with costs of litigation including attorney’s fees.

 

***In the Matter ofthe Notice of Violation, Docket Number 3852-06, Issued to Lance Oil & GasCompany, Inc., Department of Environmental Quality, Water Quality Division,State of Wyoming.***On January 26, 2006, we received aNotice of Violation issued by the State of Wyoming Department of EnvironmentalQuality, Water Quality Division, for the un-permitted discharge of coal bedmethane produced water at our Spotted Horse Facility in Campbell County. Wehave undertaken certain remedial steps to address the items contained in theNotice of Violation.

 

***In the Matter ofthe Notice of Violation, WES-1252-0501, Environment Department, Air QualityBureau, State of New Mexico.***On March 6, 2006, wereceived a Notice of Violation pertaining to operations at our San Juan RiverGas Plant located west of Farmington, New Mexico, containing two allegedviolations. On April 4, 2006,we met with the Environment Department to discuss the NOVs and any potentialmonetary penalties, which have not been determined.

 

In addition to the above claims, we are involved invarious other litigation and administrative proceedings arising in the normalcourse of business. While the outcome of claims in litigation is inherentlyuncertain, and it is not possible to predict the ultimate outcome, we intend tovigorously contest the allegations in the previously described matters. In theopinion of our management, any liabilities that may result from these claimswill not, individually or in the aggregate, have a material adverse effect onour financial position, results of operations or cash flow.

 

***NOTE 7 - RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS***

 

We continually monitor and revise our accounting policiesas new rules are issued. At this time, there are several new accountingpronouncements that have recently been issued, but not yet adopted, which willhave an impact on our accounting when they become effective.

 

**SFAS No. 151.**   SFASNo. 151, “*Inventory Costs, an amendmentof ARB No. 43, Chapter 4”*was issued in November 2004 and iseffective for Western for inventory costs incurred in fiscal years beginningafter June 15, 2005, and will be applied prospectively. SFAS No. 151amends APB Opinion No. 43, Chapter 4, “Inventory Pricing” to clarify theaccounting for abnormal amounts of costs and the allocation of fixed productionoverheads. We adopted SFAS No. 151 on January 1, 2006, and the adoption of thispronouncement did not affect our results of operations, financial position orcash flows.

 

In order to minimize transportation costs or makeproduct available at a location of our customer’s preference, from time totime, we will enter into arrangements to buy product from a party at onelocation and arrange to sell a like quantity of product to this same party atanother location.  In accordance withEITF 04-13, these transactions will be required to be reported on a sales netof purchases basis.  This EITF iseffective for transactions entered into or modified in the first interim orannual period beginning after March 15, 2006. For us this EITF will be effective in the quarter ended June 30,2006.  To the extent transactions arerequired to be netted, this will result in a reduction of revenues and costs byan equal amount, but the netting will have no impact on net income or cashflows.  

 

In accordance with EITF 03-11, we record revenue onthese transactions on a gross basis versus sales net of purchases basis becausewe obtain title to the product that we buy, bear the risk of loss, credit andperformance exposure on these transactions, and take physical delivery of theproduct.  For the quarters ended March31, 2006 

 

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and 2005, werecorded revenues of $30.7 million and $28.7 million, respectively, and productpurchases of $28.6 million and $26.7 million, respectively, for transactionswhich were entered into concurrently and with the intent to buy and sell likequantities with the same counterparty at different locations and at marketprices at those locations.  

 

**SFAS No. 154.**   In May 2005, the FASB issued SFAS No. 154, “*Accounting Changes and Error Corrections, a replacement of AccountingPrinciples Board Opinion (APB) No. 20, Accounting Changes, and FASB StatementNo. 3, Reporting Accounting Changes in Interim Financial Statements.*”This Statement requires retrospective application to prior periods' financialstatements of a change in accounting principle. It applies both to voluntarychanges and to changes required by an accounting pronouncement if thepronouncement does not include specific transition provisions. APB 20previously required that most voluntary changes in accounting principles berecognized by recording the cumulative effect of a change in accountingprinciple. SFAS 154 is effective for fiscal years beginning after December 15,2005. We adopted this statement on January 1, 2006, and the adoption of thispronouncement did not have a material effect on our financial statements.

 

**SFAS No. 155.**  In February 2006, the FASB issued SFAS No.155, “*Accounting for Certain Hybrid FinancialInstruments, an Amendment of SFAS No. 133 and No. 140*”.  This statement resolves issues addressed inSFAS Implementation Issue D1, “*Application of Statement 133to Beneficial Interests in Securitized Financial Assets*.”  This statement is effective in the annualperiod commencing after September 15, 2006. We do not believe that the adoption of this statement will have amaterial impact on our results of operation, financial position or cash flows.

 

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**ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OFFINANCIAL CONDITION AND RESULTS OF OPERATIONS**

 

The following discussion and analysis relates tofactors that have affected our consolidated financial condition and results ofoperations for the three months ended March 31, 2006 and 2005. You should alsorefer to our interim consolidated financial statements and notes theretoincluded elsewhere in this document. This section, as well as other sections inthis Form 10-Q, contain “forward-looking statements” within the meaning of thePrivate Securities Litigation Reform Act of 1995, which can be identified bythe use of forward-looking terminology, such as “may,” “intend,” “will,” “expect,”“anticipate,” “estimate,” or “continue” or the negative thereof or other variationsthereon or comparable terminology. In addition to the important factorsreferred to herein, numerous factors affecting the gas processing industrygenerally and in the specific markets for gas and NGLs in which we operatecould cause actual results to differ materially from those in suchforward-looking statements.

 

***BusinessStrategy.***Maximizing the value of our existing coreassets is the focal point of our business strategy. Our core assets are ourfully integrated upstream and midstream assets in the Powder River and GreaterGreen River Basins in Wyoming, the San Juan Basin in New Mexico, the Sand WashBasin in Colorado and our midstream operations in West Texas and Oklahoma. Ourlong-term business plan is to increase stockholder value by: (i) doublingproved natural gas reserves and equity production of natural gas from thelevels achieved in 2001 by the end of 2006; (ii) meeting or exceedingthroughput projections in our midstream operations; and (iii) optimizing annualreturns.

 

***Industry and Company Overview.***InNorth America, our industry has experienced several consecutive years ofdeclining natural gas production. Most of the major gas producing areas, suchas the Gulf of Mexico, are mature and are in production decline. We areconcentrating our efforts in the Rocky Mountain gas producing basins wherethere are estimated to be large quantities of undeveloped gas. The U.S.government 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 future production growth with a large inventoryof undeveloped drilling locations in the Powder River, the Greater Green Riverand San Juan Basins to meet the growing demand for clean burning natural gas. Inaddition, our experience and technical expertise position us to acquire newopportunities to develop natural gas in the Rocky Mountain region. Ourchallenges will be to accomplish these goals with the difficulties encounteredby the industry in obtaining the necessary permits from the BLM, and stateagencies such as the Wyoming Department of Environmental Quality, or DEQ. Webelieve that our technical expertise in developing environmentally responsiblesolutions to the problems encountered in the development of gas reserves willbe a competitive advantage in overcoming these challenges.

 

Our operations areconducted through the following four business segments:

 

***Explorationand Production.***We explore for, develop and produce naturalgas reserves independently which also may enhance and support our existinggathering and processing operations. Our producing properties are primarilylocated in the Powder River, Greater Green River, San Juan, and the Sand WashBasins. These plays are relatively low-risk, multi-year development projects. Theseprovide us with the opportunity to steadily increase our production volume overtime at reasonable operating and low finding and development costs. In thefirst quarter of 2006, our average production sold was 188 MMcfe per day, whichwas a 14.6% increase over the average production volume sold in the firstquarter of 2005.

 

We continue to seek toadd additional upstream core projects that are focused on Rocky Mountainnatural gas. We will utilize our expertise in exploration and low-riskdevelopment of unconventional gas reservoirs including tight-gas sands, CBM,biogenic, and shale gas plays to evaluate acquisitions of additionalleaseholds, proved and undeveloped reserves or companies with operationsprimarily focused on unconventional gas developments. In 2005, we opened anexploration and production office in Calgary, Alberta, Canada to evaluateopportunities in the Western Canadian Sedimentary Basin. In total, throughMarch 31, 2006, we have acquired leases on approximately 1.0 million net acresin areas outside our primary producing areas and continue to actively acquireadditional leasehold positions.

 

In March 2006, we acquiredcertain CBM properties and related gathering assets in the Big George fairwayof the Powder River Basin of Wyoming for approximately $136.7 million beforeadjustments. This acquisition was funded with amounts available under ourrevolving credit facility. Thepurchase price includes the drilling rights on approximately 40,000 gross andnet acres and 110 drilled wells. Approximately 70 of the drilled wells arecurrently dewatering, and the remaining 40 wells are awaiting hookup.

 

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***Gathering,Processing and Treating.***Our core operations are inwell-established areas such as the Permian, Anadarko, Powder River, GreaterGreen River, and San Juan Basins. We connect natural gas from gas and oil wellsto our gathering systems for delivery to our processing or treating plantsunder long-term contracts. At our plants we process natural gas to extract NGLsand may treat natural gas in order to meet pipeline specifications. We providethese services to major oil and gas companies, to independent producers ofvarious sizes and for our own production. We believe that our low cost ofoperations, our high on-line time and our safety records are key elements inour ability to compete effectively and provide service to our customers. Ourexpertise in gathering, processing and treating operations can enhance theeconomics 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. Overallthroughput in our facilities during the first quarter of 2006 increasedslightly as compared to the same period in 2005 and averaged a total of 1.38Bcf per day.

 

***Transportation.***In the Powder River Basin, we own one interstatepipeline, MIGC, Inc., and one intrastate pipeline, MGTC, Inc., which transportnatural gas produced by us, natural gas for producers and energy marketersunder fee schedules regulated by state or federal agencies.

 

***Marketing.***Our gas marketing segment is an outgrowth of our gasprocessing and upstream activities and ensures continual flow of our producedproducts. One of the primary goals of our gas marketing operations is thepreservation and enhancement of the value received for our equity volumes ofnatural gas. This goal is achieved through the use of hedges on the productionof our equity natural gas and NGLs and through the use of firm transportationcapacity. Historically, the gas produced in the Rocky Mountain region hastraded at a substantial discount as compared to the Mid-Continent and WestCoast areas, as a result of limited pipeline capacity from the region. We havehistorically used our firm pipeline transportation capacity to access higherpriced Mid-Continent markets and markets further east for both our equityproduction and for gas purchased from third-parties in the Rocky Mountainregion.

 

We also buy and sellnatural gas and NGLs in the wholesale market in the United States and Canada. Thesethird-party sales, our firm transportation capacity on interstate pipelines andour 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.

 

***RESULTS OF OPERATIONS***

 

**Three months ended March 31, 2006compared to the three months ended March 31, 2005**

**(Dollars in thousands, except pershare amounts and operating data).**

 
| ** **                                                  | ** ** | **Quarter Ended March 31,** | ** ** |
|-------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                  | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **Percent  Change** | ** ** |
| **Financial results:**                                 | ** ** | ** **                                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| Revenues                                                    |       | $                                          | 989,081    |   | $ | 834,107 |   | 19 |   |
| Net income                                                  |       | 61,862                                     |       | 19,706 |   | 214 |   |
| Earnings per share of common stock                          |       | 0.82                                       |       | 0.27 |   | 204 |   |
| Earnings per share of common stock – assuming dilution |       | 0.81                                       |       | 0.26 |   | 208 |   |
| Net cash  provided by operating activities                  |       | 188,010                                    |       | 117,396 |   | 60 |   |
| Net cash used in  investing activities                      |       | (263,899                                   | )          | (114,241 | ) | (131 | ) |
| Net cash  provided by (used in) financing activities        |       | 56,271                                     |       | (1,820 | ) | 3,238 |   |
|                                                        |       |                                       |       |   |   |   |   |
| **Operating  data:**                                        |       |                                       |       |   |   |   |   |
| Average gas  sales (MMcf/D)                                 |       | 1,107                                      |       | 1,302 |   | (15 | ) |
| Average NGL  sales (MGal/D)                                 |       | 1,836                                      |       | 1,763 |   | 4 |   |
| Average gas  prices ($/Mcf)                                 |       | $                                          | 7.72       |   | $ | 5.91 |   | 31 |   |
| Average NGL  prices ($/Gal)                                 |       | $                                          | 1.01       |   | $ | 0.84 |   | 20 |   |

 

Net income increased $42.2million for the three months ended March 31, 2006 compared to the same periodin 2005. In this quarter, we had higher production of equity gas volumes andhigher product prices as compared to the first quarter of 2005. In addition tothe benefit of higher production and prices, net income also increased due toan increase in the non-cash mark-to-market valuation of our derivatives. Partiallyoffsetting these items was an increase in depreciation, depletion andamortization and selling and administrative expenses in the first quarter of2006.

 

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Revenues from the sale ofgas increased $75.4 million to $771.7 million for the three months ended March31, 2006 compared to the same period in 2005. This increase was primarily due toan increase in product prices in the three months ended March 31, 2006. Averagegas prices realized by us increased $1.81 per Mcf to $7.72 per Mcf for thequarter ended March 31, 2006 compared to the same period in 2005. Included inthe realized gas price were approximately $8.5 million of gains recognized inthe three months ended March 31, 2006 related to futures positions on equitygas volumes. We have entered into additional futures positions forapproximately 75% of our equity gas for the remainder of 2006 and to a lesserextent for 2007. See further discussion in “Item 3. Quantitative andQualitative Disclosures About Market Risk”. Average gas sales volumes decreasedby 15% to 1,107 MMcf per day for the quarter ended March 31, 2006 compared tothe same period in 2005.

 

Revenues from the sale ofNGLs increased $34.4 million to $167.4 million for the three months ended March31, 2006 compared to the same period in 2005. This increase is primarily due toan increase in product prices. Average NGL prices realized by us increased$0.17 per gallon to $1.01 per gallon for the three months ended March 31, 2006compared to the same period in 2005. We have entered into futures positions forapproximately 55% of our equity NGL production for the remainder of 2006. Seefurther discussion in “Item 3. Quantitative and Qualitative Disclosures AboutMarket Risk”. Average NGL sales volumes increased 4% to 1,836 MGal per day forthe three months ended March 31, 2006 compared to the same period in 2005.

 

The effect of Price riskmanagement activities changed from $(20.2) million for the quarter ended March31, 2005 to $21.0 million for the quarter ending March 31, 2006. This changewas due to the non-cash mark-to-market adjustments of our risk managementactivities. This account was primarily affected by changes in the forward priceof natural gas in the 2006 quarter as compared to 2005 quarter and the impactof those price changes on the fair value of the forward sale derivatives forour gas in storage.

 

Product purchases increasedby $68.8 million for the quarter ended March 31, 2006 compared to the sameperiod in 2005 as a result of the increase in product prices. Overall, combinedproduct purchases as a percentage of sales of all products decreased to 83% inthe first quarter of 2006 as compared to 85% in the first quarter of 2005. Thisdecrease is due to the reduction in third party sales volumes of natural gasand an increase in our equity production.

 

Plant and transportationoperating expense increased by $4.5 million for the quarter ended March 31,2006 compared to the same period in 2005. The increase was primarily due toincreases in labor costs, and costs for chemicals, lubricants and othersupplies.

 

Oil and gas explorationand production expenses increased by $3.6 million for the quarter ended March31, 2006 compared to the same period in 2005. The increase was substantiallydue to higher production taxes resulting from increased product prices. Overall,lease operating expenses, or LOE, averaged $0.77 per Mcf for the quarter endedMarch 31, 2006, and LOE in the Powder River Basin coal bed development averaged$0.78 per Mcf. In the Powder River Basin, this represents a decrease of $0.09per Mcf as compared to the quarter ended March 31, 2005. The decrease in LOE perMcf in the Powder River Basin is substantially due to higher production volumeswithout corresponding increases in costs.

 

Depreciation, depletion and amortization, orDD&A, increased by $6.3 million in the quarter ended March 31, 2006compared to the same period in 2005. In total, we had a $2.3 million increasein DD&A in our midstream operations primarily due to our expanding CBMgathering system in the Powder River Basin and a $3.5 million increase inDD&A in our upstream operations primarily due to our continued developmentin the Powder River Basin.

 

Selling andadministrative expenses increased by $6.3 million for the quarter ended March31, 2006 as compared to the same period in 2005. This increase was primarilythe result of increased administrative salaries and benefits, insurance, andcompensation expense related to our restricted stock plan and the January 1,2006 implementation of SFAS 123(R), which requires the expensing ofcompensation related to options on our common stock in addition to compensationrelated to our restricted stock.

 

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***Adoption of FAS 123(R)***

 

OnJanuary 1, 2006, we adopted Statement of Financial Accounting Standards No. 123(revised 2004), “Share-Based Payment”, or SFAS 123(R), which requiresthe measurement and recognition of compensation expense for all share-basedpayment awards made to employees and directors including employee stock optionsbased on estimated fair values. SFAS 123(R) supersedes our previous accountingunder Accounting Principles Board Opinion No. 25, “Accounting for Stock Issuedto Employees”, or APB 25, for periods beginning in fiscal 2006. In March 2005,the SEC issued Staff Accounting Bulletin No. 107, or SAB 107, relating to SFAS123(R). We considered the guidance of SAB 107 in our adoption of SFAS 123(R).

 

Weadopted SFAS 123(R) using the modified prospective transition method, whichrequires the application of the accounting standard as of January 1, 2006. Inaccordance with the modified prospective transition method, our ConsolidatedFinancial Statements for prior periods are not restated to reflect, and do notinclude, any impact of SFAS 123(R). We did not modify any outstanding stockoptions in anticipation of the adoption of SFAS 123(R). The effect of thechange in accounting principle resulting from the adoption of SFAS 123R wasrecognized in our financial statements through the elimination of previouslyrecognized deferred compensation costs, with offsetting amounts recorded in theadditional paid-in capital account within Stockholders’ equity.

 

Stock-based compensationexpense to be recognized under SFAS 123(R) for the three months ended March 31,2006 related to employee stock options, including compensation from ourFebruary 2006 grants is as presented in the following table. There was noadditional stock-based compensation expense related to employee stock optionsduring the three months ended March 31, 2005 resulting from the adoption ofSFAS 123(R).

 
| **(Amounts in thousands, except per share amounts)** | ** ** | **Quarter ended  March 31, 2006** | ** ** |
|------------------------------------------------------------------------------------|------------|--------------------------------------------------|------------|
| Incremental  stock-based compensation expense recognized through earnings          |       | $                                                | 2,842      |   |
| Related deferred  income tax benefit                                               |       | (1,028                                           | )          |
| Decrease in net  income                                                            |       | 1,814                                            |       |
| Decrease in  earnings per share of common stock                                    |       | 0.02                                             |       |
| Decrease in  earnings per share of common stock – assuming dilution           |       | 0.02                                             |       |
| Stock-based  compensation expense capitalized                                      |       | $                                                | 574        |   |

 

SFAS 123(R) requires usto estimate the fair value of share-based payment awards on the date of grantusing an option-pricing model. The value of the portion of the award that isultimately expected to vest is recognized as expense over the requisite serviceperiods in our Consolidated Statement of Operations. Prior to the adoption ofSFAS 123(R), we accounted for stock-based awards to employees and directorsusing the intrinsic value method in accordance with APB 25 as then allowedunder Statement of Financial Accounting Standards No. 123, “Accounting forStock-Based Compensation”, or SFAS 123. Under the intrinsic value method, withthe exception of the options granted under the Chief Executive Officer andPresident’s Plan, no stock-based compensation expense had been recognized inour Consolidated Statement of Operations, because the exercise price of ourstock options granted to employees and directors equaled the fair market valueof the underlying stock at the date of grant.

 

Stock-based compensationexpense to be recognized is based on the value of the portion of share-basedpayment awards that is ultimately expected to vest during the period. Stock-basedcompensation expense recognized in our Consolidated Statement of Operations forthe first quarter of 2006 includes compensation expense for share-based paymentawards granted prior to, but not yet vested, as of January 1, 2006. Thisexpense is based on the grant date fair value estimated in accordance with thepro forma provisions of SFAS 123. Compensation expense for the share-basedpayment awards granted subsequent to December 31, 2005 will be based on thegrant date fair value estimated in accordance with the provisions of SFAS123(R). In conjunction with the adoption of SFAS 123(R), we continued ourmethod of attributing the value of stock-based compensation using thestraight-line single option method. As stock-based compensation expenserecognized in the Consolidated Statement of Operations for the first quarter of2006 is based on awards ultimately expected to vest, it will be reduced forestimated forfeitures. SFAS 123(R) requires forfeitures to be estimated at thetime of grant and revised, if necessary, in subsequent periods if actualforfeitures differ from those estimates. At March 31, 2006, the compensationexpense related to non-vested awards to be recognized in future periods totals$26.2 million. The weighted average period over which this expense is expectedto be recognized is 2.2 years.

 

***Cash FlowInformation***

 

Cash flows from operatingactivities increased by $70.6 million in the first quarter of 2006 compared tothe first quarter of 2005. This increase was primarily due to the increase inNet income and the timing of cash receipts and

 

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payables, and the change in our natural gas inventory positions.

 

Cash flows used in investingactivities increased by $149.7 million in the first quarter of 2006 compared tothe first quarter of 2005. This increase was primarily due to an increasedlevel of capital expenditures, including the March 2006 acquisition ofproperties in the Powder River Basin.

 

Cash flows provided byfinancing activities increased by $58.1 million in the first quarter of 2006compared to the first quarter of 2005. This increase was due to the utilizationof our revolving credit facility to fund our capital investments in 2006,including the acquisition of properties in the Powder River Basin in the firstquarter.

 

***Segment Information***

 

***Gas Gathering, Processing and Treating.***The GasGathering, Processing and Treating segment realized segment-operating profit of$56.4 million for the three months ended March 31, 2006 compared to $52.3million in the same period in 2005. The increase in operating profit in thissegment in the first quarter of 2006 was primarily due to higher realizedprices and a 2% increase in throughput volume.

 

***Exploration and Production.***TheExploration and Production segment realized segment-operating profit of $68.0million in the first quarter of 2006 compared to $39.0 million in 2005. Theincrease was due to increased equity production and higher product prices. Duringthe first quarter of 2006, our production of natural gas as compared to thesame period in 2005 increased by 18% to 16.9 Bcfe. The following table setsforth the average sales price received for our oil and gas products along withcost information in the three months ended March 31, 2006 and 2005. 

 
| ** **                                              | ** ** | **Quarter Ended March 31,** | ** ** |
|---------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                              | ** ** | **2006**                                   | ** ** | **2005** | ** ** |
| Average sales  price: (1)                               |       |                                       |       |   |   |
| Oil ($/Bbl),  excluding the effect of hedging positions |       | $                                          | 58.46      |   | $ | 43.83 |   |
| Oil ($/Bbl),  including the effect of hedging positions |       | 58.46                                      |       | 43.83 |   |
|                                                    |       |                                       |       |   |   |
| Gas ($/Mcf),  excluding the effect of hedging positions |       | 6.12                                       |       | 4.89 |   |
| Gas ($/Mcf),  including the effect of hedging positions |       | 6.57                                       |       | 4.97 |   |
|                                                    |       |                                       |       |   |   |
| Production and  other costs:                            |       |                                       |       |   |   |
| Lease operating  expense ($/Mcfe)                       |       | 0.77                                       |       | 0.87 |   |
| Production tax  expense ($/Mcfe)                        |       | 0.66                                       |       | 0.47 |   |
| Gathering and  transportation expense ($/Mcfe)          |       |                                       |       |   |   |
| Inter-segment  gathering and transportation charges     |       | 0.64                                       |       | 0.63 |   |
| Third-party  transportation charges                     |       | 0.22                                       |       | 0.20 |   |
| Other expenses  ($/Mcfe)                                |       | 0.02                                       |       | 0.01 |   |
| Total costs  ($/Mcfe)                                   |       | $                                          | 2.31       |   | $ | 2.18 |   |

 

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| (1) The prices  received for NGLs are included in the price received for gas. |   |
|-------------------------------------------------------------------------------|--------|

 

***Marketing.***The Marketing segmentrealized a segment-operating profit of $25.3 million for the three months endedMarch 31, 2006 compared to a segment-operating loss of ($18.4) million in thesame period of 2005. The increase in segment-operating profit was primarily dueto non-cash mark-to-market gains from economic hedges of future sales of gasutilizing our storage and transportation capacity for the quarter ended March31, 2006 compared to a loss for the quarter ended March 31, 2005.

 

***Transportation.***The Transportationsegment realized segment-operating profit of $4.0 million for the three monthsended March 31, 2006 compared to $3.3 million in the same period of 2005. TheTransportation segment includes the results from the MIGC and MGTC pipelines inthe Powder River Basin.

 

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

#### ** **

#### **Our sources of liquidity and capital resourceshistorically have been net cash provided by operating activities, fundsavailable under our financing facilities and proceeds from offerings of debtand equity securities. In the past, these sources have been sufficient to meetour needs and finance the growth of our business. We can give no assurance thatthe historical sources of liquidity and capital resources will be available forfuture development and acquisition projects, and we may be required to seekadditional or alternative financing sources. Product prices, hedges of equityproduction, sales of inventory, the volume of**

 

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#### **natural gas processed by ourfacilities, the volume of natural gas produced from our producing properties,the margin on third-party product purchased for resale, as well as the timelycollection of our receivables and the availability and cost of oil fieldservices and supplies such as concrete, steel pipe and compression equipmentare all expected to have significant influences on our future net cash providedby operating activities. Additionally, our future growth will be dependent uponthe success and timing of our exploration and production activities, obtainingadditions to dedicated plant reserves, acquisitions, new project development,marketing results, efficient operation of our facilities and our ability toobtain 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 andproduction associated with our producing properties will depend upon, amongother factors, the price for gas, availability of transportation capacity tomarket centers, the energy and environmental policy and regulation bygovernmental agencies, the drilling schedules of the operators of ournon-operated properties, the issuance of drilling and water disposal permits,the availability of oil field services, and the length of time for wells in thePowder River Basin to be dewatered, none of which is within our control. Asignificant reduction in the level of our production or a significant reductionin natural gas prices could have a material adverse effect on our financialcondition, 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, the overall level of drilling associated withour plant facilities will depend upon, among other factors, the prices for oiland gas, the drilling budgets of third-party producers, availability oftransportation capacity to market centers, the energy and environmental policyand regulation by governmental agencies, and the pace at which drilling permitsare received, none of which is within our control. There is no assurance thatwe will continue to be successful in replacing the dedicated reserves processedat our facilities. Any prolonged reduction in prices for natural gas and NGLsmay depress the levels of exploration, development and production by thirdparties. Lower levels of these activities could result in a correspondingdecline in the demand for our gathering, processing and treating services. Asignificant reduction in any of these activities could have a material adverseeffect on our financial condition, results of operations and cash flows.

 

Inthe third quarter of 2005, the Gulf Coast of the United States was impacted bytwo major hurricanes. These storms resulted in the curtailment of natural gasand oil production from the Gulf of Mexico, and the operations of majorrefineries and gas processing facilities in Texas, Louisiana and Mississippi. Ouroperations did not sustain any physical damage from these hurricanes, and ourliquidity was not materially impacted as our counterparties and customerscontinued to make timely payments. However, in September 2005, one of ourcustomers, a utility serving the New Orleans area, filed for bankruptcyprotection under Chapter 11 of the Bankruptcy Code. At the time of thebankruptcy filing, we had an outstanding account receivable from this utilityof $4.1 million. In the third quarter of 2005, we reserved $800,000 againstthis amount, which represents our best estimate of the current market value ofthis receivable.

 

Webelieve that the amounts available to be borrowed under our financingfacilities, together with the 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 onthe timing and the amount of our future projects, we may be required to seekadditional sources of capital. Our ability to secure such capital is restrictedby our financing facilities, although we may request additional borrowingcapacity from our lenders, seek waivers from our lenders to permit us to borrowfunds from third-parties, seek replacement financing facilities from otherlenders, use stock as a currency for acquisitions, sell existing assets or usea combination of these alternatives. While we believe that we would be able tosecure additional financing, if required, we can provide no assurance that wewill be able to do so or as to the terms of any additional financing.

 

Weexpect our dividends to total approximately $22.5 million in 2006. Thesedividends, and our $10.0 million of scheduled repayments of long-term debt in2006, are expected to be funded with amounts available under the revolvingcredit facility.

 

***Sources and Uses of Funds*.**Our sourcesand uses of funds for the quarter ended March 31, 2006 are summarized asfollows (dollars in thousands):

 

24

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| **Sources  of funds:**                                                     |   |    |      |
|----------------------------------------------------------------------------|--------|---------|-----------|
| Borrowings under  our revolving credit facility                            |   | $       | 957,100   |   |
| Proceeds from  the dispositions of property and equipment                  |   | 1,152   |      |
| Net cash  provided by operating activities                                 |   | 188,010 |      |
| Excess tax  benefits from share-based payment awards                       |   | 1,484   |      |
| Proceeds from  exercise of common stock options                            |   | 4,806   |      |
| Total sources of  funds                                                    |   | $       | 1,152,552 |   |
| **Uses of  funds:**                                                        |   |    |      |
| Payments under  our revolving credit facility (including debt issue costs) |   | $       | 872,114   |   |
| Capital  expenditures                                                      |   | 265,051 |      |
| Change in  outstanding checks                                              |   | 29,344  |      |
| Common dividends  paid                                                     |   | 5,661   |      |
| Total uses of  funds                                                       |   | $       | 1,172,170 |   |

 

***Capital Investment Program.***Wecurrently anticipate capital expenditures in 2006 of approximately $675.8million. The 2006 capital budget is a 45% increase over the amount expended in2005. This increase is the result of our March 2006 acquisition of certain CBMproperties and an expected increase in drilling activity in each of our core upstreamareas and additional drilling activity by third party producers whose acreageis dedicated to our midstream facilities. Overall, capital expenditures in thePowder River Basin CBM development and in the Greater Green River Basinoperations represent 52% and 22%, respectively, of the total 2006 budget. Thisbudget may be increased to provide for acquisitions if approved by our board ofdirectors.

 

The 2006 capital budgetand our capital expenditures during the quarter ended March 31, 2006 arepresented in the following table (dollars in thousands).

 
| **Type of Capital Expenditure**               | ** ** | **2006 Capital  Budget** | ** ** | **Capital Expenditures  During the Quarter  Ended  March 31, 2006** | ** ** |
|--------------------------------------------------------------|------------|-------------------------------|------------|----------------------------------------------------------------------------------------------|------------|
| Gathering,  processing, treating and pipeline assets         |       | $                             | 185.0      | *                                                                                            | $          | 71.4 | * |
| Exploration and  production and lease acquisition activities |       | 336.2                         |       | 65.4                                                                                         |       |
| Acquisition of  CBM properties                               |       | 136.7                         |       | 136.7                                                                                        |       |
| Information  technology and other items                      |       | 4.5                           |       | 0.5                                                                                          |       |
| Capitalized  interest and overhead                           |       | 13.4                          |       | 5.4                                                                                          |       |
| Total Capital  Expenditures                                  |       | $                             | 675.8      |                                                                                         | $          | 279.4 |   |

 

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*  Includes $22.2 million budgeted in 2006 and$3.7 million expended in the first quarter of 2006 for maintaining existingfacilities.

 

InMarch 2006, we acquired certain CBM properties and related gathering assets inthe Big George fairway of the Powder River Basin of Wyoming for approximately$136.7 million before adjustments. This acquisition was funded with amountsavailable under our revolving credit facility. The purchase price includes the drilling rights onapproximately 40,000 gross and net acres and 110 drilled wells. Approximately70 of the drilled wells are currently dewatering and the remaining 40 wells areawaiting hookup.

 

***Contractual Commitments and Obligations***

 

##### ***ContractualCommitments and Cash Obligations.***Asummary of our contractual commitments and cash obligations as of March 31,2006 is as follows (dollars in thousands):

 
| ** **                                 | ** ** | ** ** | ** ** | **Payments Due by Period** | ** ** |
|--------------------------------------------|------------|------------|------------|-------------------------------------------|------------|
| **Contractual Obligations (1)**  | ** ** | **Total**  | ** ** | **Due in 2006**                 | ** ** | **Due in  2007 – 2008** | ** ** | **Due in  2009 – 2010** | ** ** | **Due   Thereafter** | ** ** |
| Guarantee of  Fort Union Project Financing |       | $          | 4,057      |                                      | $          | 781 |   | $ | 2,313 |   | $ | 963 |   | $ | — |   |
| Operating Leases                           |       | 71,579     |       | 13,909                                    |       | 32,716 |   | 20,232 |   | 4,722 |   |
| Firm  Transportation Capacity Agreements   |       | 238,899    |       | 33,958                                    |       | 85,760 |   | 59,283 |   | 59,898 |   |
| Firm Storage  Capacity Agreements          |       | 40,158     |       | 9,751                                     |       | 17,886 |   | 5,258 |   | 7,263 |   |
| Long-term Debt                             |       | 515,000    |       | 10,000                                    |       | 10,000 |   | 370,000 |   | 125,000 |   |
| Interest on Long-term  Debt (2)            |       | 113,144    |       | 22,221                                    |       | 57,319 |   | 25,026 |   | 8,578 |   |
| Total  Contractual Cash Obligations        |       | $          | 982,837    |                                      | $          | 90,620 |   | $ | 205,994 |   | $ | 480,762 |   | $ | 205,461 |   |

 

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(1)  Not included in the table are approximately$3.0 million per year of various payments for right-of-way, surface use andmidstream and upstream site leases that are cancelable when the properties areno longer in use.

 

(2) The interest rateassumed on the revolving credit facility at March 31, 2006 is 5.7% per annum. Actualinterest rates are assumed for the debt under our master shelf agreement.

 

***Guarantee of Fort Union Project Financing.***Weown a 15% equity interest in Fort Union Gas Gathering, L.L.C., or Fort Union,and are the construction manager and field operator. Fort Union gathers andtreats natural gas in the Powder River Basin in northeast Wyoming. Initialconstruction and subsequent expansions of the gathering header and treatingsystem have been project financed by Fort Union. This debt is amortizing on anannual basis with the final payment due in 2009. Our requirement to fund underthis guarantee would be reduced by the value of assets held by Fort Union. Thisguarantee is not reflected on our Consolidated Balance Sheet.

 

***Operating Leases.***In the ordinarycourse of our business operations, we enter into operating leases for officespace, and for office, communication, transportation and compression equipment.Payments made on these leases are a component of operating expenses and arereflected on the Consolidated Statement of Operations and, as operating leases,are not reflected on our Consolidated Balance Sheet. Our operating leases haveterms ranging from one month to ten years, and the majority of the equipmentleases have return or fair market purchase options available at various timesduring the lease. If we were to exercise the purchase options on all the leasedcompression equipment, these purchase options would require the capitalexpenditure of approximately $45.0 million between 2007 and 2013.

 

***FirmTransportation Capacity.***Access to firm transportation isalso a significant element of our business strategy. Firm transportationensures that our equity production has access to downstream markets and allowsus to capture incremental profit when pricing differentials between physicallocations occur. Firm transportation agreements generally require the paymentof fixed monthly fees regardless of the quantity of gas that flows under aparticular agreement. These agreements are not reflected on our ConsolidatedBalance Sheet.

 

The fixed fees associatedwith our existing contracts for firm transportation capacity during 2006 willaverage approximately $0.17 per Mcf. The associated contract periods range fromone month to eleven years. Under firm transportation contracts, we are requiredto pay the fees associated with these contracts whether or not thetransportation is used.

 

***FirmStorage Capacity Agreements*.**We customarily store gas in underground storage facilities to ensure anadequate supply for long-term sales contracts and to capture seasonal pricedifferentials. As of March 31, 2006, we had contracts in place forapproximately 17.0 Bcf of storage capacity at various third-party facilities. Firmstorage agreements generally require the payment of fixed monthly feesregardless of the quantity of gas that is in storage under a particularagreement.

 

The fees associated with these contracts in 2006will average $0.76 per Mcf of annual capacity. The associated contract periods at March31, 2006 had an average term of 36 months. At March 31, 2006, we held gas inour contracted storage facilities and in imbalances of approximately 14.0 Bcfat an average cost of $6.76 per Mcf compared to 13.4 Bcf at an average cost of$5.83 perMcf at March 31, 2005. These positions are for storage withdrawals within thenext thirteen months. At the time we place product into storage, we contractfor the sale of that product, physically or financially, and do not speculateon the future value of the product.

 

At March 31, 2006, weheld NGLs in line pack and in storage at various third-party facilities of2,770 MGal, consisting primarily of propane and ethane, at an average cost of$0.39 per gallon compared to 3,669 MGal at an average cost of $0.45 per gallonat March 31, 2005.

 

#### **Long-termDebt**

#### ** **

*** Revolving Credit Facility.***At March 31, 2006, the commitment under therevolving credit facility was $700 million with a maturity date in November2010. At March 31, 2006, $370.0 million was outstanding under thisfacility. Loans made under this facility are secured by a pledge of the capitalstock of our significant subsidiaries, and these subsidiaries also guaranteethe borrowings under the facility.

 

The borrowings under ourcredit facility bear interest at Eurodollar rates or a base rate, as requestedby us, plus an applicable percentage based on our debt to capitalization ratio.The base rate is the agent’s published prime rate. We also pay a quarterlycommitment fee on undrawn amounts ranging between 0.10% and 0.30%, depending onour

 

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debtto capitalization ratio. This fee is paid on unused amounts of the commitment. Asof March 31, 2006, the interest rate payable on borrowings under this facilitywas approximately 5.7% per year. Under the credit facility, we are subject to anumber 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 equally with borrowings under our master shelfagreement with The Prudential Insurance Company. This facility has been ratedBa1 by Moody’s and BB+ by Standard and Poor’s.

 

***MasterShelf Agreement.***Amounts outstanding under our mastershelf agreement at March 31, 2006 are as indicated in the following table(dollars in thousands): 

 
| **Issue Date** | ** ** | **Amount** | ** ** | **Interest   Rate** | ** ** | **Final  Maturity** | ** **    | **Principal   Repayment Schedule** | ** **                        |
|---------------------|------------|------------|------------|--------------------------|------------|---------------------|---------------|----------------------------------------------|-----------------------------------|
| July 28, 1995       |       | $          | 20,000     |                     | 7.61       | %                   | July 28, 2007 |                                         | $10,000 on July 28, 2006 and 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               |       | $          | 145,000    |                     |       |                |          |                                         |                              |   |

 

Our borrowings under ourmaster shelf agreement are secured by a pledge of the capital stock of oursignificant subsidiaries. These subsidiaries also guarantee the borrowingsunder this facility. All of the borrowings under our master shelf agreement canbe prepaid prior to their final maturity by paying 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 our master shelfagreement, to interest for the last four quarters in excess of 3.0 to 1.0. During2006, we will make scheduled payments totaling $10.0 million on this facility. Weintend to fund this repayment with funds available under the revolving creditfacility.

 

***Upstream Operations***

 

A vital aspect of ourlong-term business plan is to double proved 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 developmentof our leasehold positions in the Powder River Basin CBM development, theGreater Green River Basin, and the San Juan Basin. Each of our existingupstream core projects in these areas are substantially integrated with ourmidstream operations. In other words, in these areas, we provide a significantamount of the gathering, compression, processing, marketing or transportationservices for our own production and also provide these services for third-partyoperators. Additionally, we are actively pursuing new exploration, developmentand producing property acquisition opportunities in unconventional gasdevelopments in the United States and Canada.

 

#### **Our principal upstream operations are summarized inthe following table:**

 
| **Production Area**   | ** ** | **Gross Acres  Under Lease at  March 31,  2006** | ** ** | **Net Acres  Under Lease  at March 31,  2006** | ** ** | **Average Net  Production Sold  for the Quarter  Ended  March 31,  2006  (MMcfe/day)** | ** ** | **Gross  Productive  Gas Wells at  March 31,  2006** | ** ** | **Net  Productive  Gas Wells at  March 31,  2006** | ** ** |
|----------------------------|------------|----------------------------------------------------------------------|------------|--------------------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------------|------------|-------------------------------------------------------------------|------------|
| Powder River  Basin CBM    |       | 1,062,000                                                            |       | 561,000                                                            |       | 125                                                                                                             |       | 5,387                                                               |       | 2,547                                                             |       |
| Pinedale  Anticline/Jonah  |       | 132,000                                                              |       | 24,000                                                             |       | 45                                                                                                              |       | 384                                                                 |       | 43                                                                |       |
| San Juan Basin             |       | 30,000                                                               |       | 29,000                                                             |       | 12                                                                                                              |       | 185                                                                 |       | 164                                                               |       |
| Sand Wash Basin            |       | 113,000                                                              |       | 107,000                                                            |       | 5                                                                                                               |       | 23                                                                  |       | 23                                                                |       |
| Red  Desert/Washakie/Uinta |       | 76,000                                                               |       | 47,000                                                             |       | 1                                                                                                               |       | 8                                                                   |       | 3                                                                 |       |
| Denver-Julesburg  Basin    |       | 385,000                                                              |       | 331,000                                                            |       | —                                                                                                          |       | 9                                                                   |       | 9                                                                 |       |
| Canada                     |       | 44,000                                                               |       | 43,000                                                             |       | —                                                                                                          |       | 22                                                                  |       | 21                                                                |       |
| Central Montana            |       | 639,000                                                              |       | 562,000                                                            |       | —                                                                                                          |       | —                                                              |       | —                                                            |       |
| Other                      |       | 30,000                                                               |       | 26,000                                                             |       | —                                                                                                          |       | 10                                                                  |       | 2                                                                 |       |
| Total                      |       | 2,511,000                                                            |       | 1,730,000                                                          |       | 188                                                                                                             |       | 6,028                                                               |       | 2,812                                                             |       |

 

***Drilling Results.***The following tablesets forth the number of wells we completed during the quarters ended March 31,2006 and 2005 in each of our major producing areas. This information should notbe considered to be indicative of future performance, nor should it be assumedthat there is necessarily any correlation between the

 

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number of productive wells drilled, quantities of reserves found oreconomic value. Productive wells are producing wells and wells capable ofproduction.

 
| ** **                               | ** ** | **Three Months Ended March 31,** | ** ** |
|------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                               | ** ** | **2006**                                             | ** ** | **2005** | ** ** |
| **Productive Area**                 | ** ** | **Gross**                                            | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| **Powder  River Basin CBM**              |       |                                                 |       |   |   |   |   |   |   |
| Productive wells  completed              |       | 207                                                  |       | 93 |   | 145 |   | 77 |   |
|                                     |       |                                                 |       |   |   |   |   |   |   |
| **Pinedale  Anticline and Jonah Fields** |       |                                                 |       |   |   |   |   |   |   |
| Development  productive wells completed  |       | 8                                                    |       | 1 |   | 7 |   | 1 |   |
| Exploratory  productive wells completed  |       | 2                                                    |       | 0 |   | 3 |   | 0 |   |
| Dry exploratory  wells drilled           |       | 0                                                    |       | 0 |   | 1 |   | 0 |   |
|                                     |       |                                                 |       |   |   |   |   |   |   |
| **San  Juan Basin**                      |       |                                                 |       |   |   |   |   |   |   |
| Development  productive wells completed  |       | 9                                                    |       | 9 |   | 12 |   | 11 |   |
| Exploratory  productive wells completed  |       | 4                                                    |       | 4 |   | 5 |   | 5 |   |
|                                     |       |                                                 |       |   |   |   |   |   |   |
| **Sand  Wash Basin**                     |       |                                                 |       |   |   |   |   |   |   |
| Dry exploratory  wells completed         |       | 0                                                    |       | 0 |   | 1 |   | 1 |   |
|                                     |       |                                                 |       |   |   |   |   |   |   |
| **Canada  (1)**                          |       |                                                 |       |   |   |   |   |   |   |
| Exploratory  productive wells completed  |       | 4                                                    |       | 4 |   | 0 |   | 0 |   |
|                                     |       |                                                 |       |   |   |   |   |   |   |
| **Other  (1)**                           |       |                                                 |       |   |   |   |   |   |   |
| Exploratory  productive wells completed  |       | 3                                                    |       | 1 |   | 0 |   | 0 |   |

 

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(1)          Some exploratorywells while classified as productive are still in the process of an extendedproduction test.

 

***Powder River Basin Coal Bed Methane.***Wecontinue to develop our Powder River Basin CBM reserves and expand theassociated gathering system in northeast Wyoming. Our net production sold fromthe Powder River Basin CBM averaged 125 MMcf per day in the first quarter of2006.

 

Ourproduction from the Big George coal continues to increase and averaged 185 MMcfper day gross, or 71 MMcf per day net, in April 2006 from various developmentareas. In these development areas and our areas of exploration, as of March 31,2006, we had 1,217 gross Big George wells producing gas, 1,367 gross Big Georgewells dewatering or awaiting connection to begindewatering. Typically a period of dewatering lasting from a few tothirty-six months, or in some cases longer, is required prior to obtainingsufficient gas production to justify capital expenditures for compression andgathering, and to classify the reserves as proved.

 

Drilling in the PowderRiver Basin is dependent on the receipt of various regulatory permits,including BLM drilling permits, Wyoming DEQ water discharge permits, and theWyoming State Engineer’s Office reservoir permits. Most of our undevelopedprospects from the Big George formation are located in the Powder River drainagearea. Water management techniques utilized by us, and approved by the DEQ on asite-specific basis, have included containment or treating. In order tofacilitate the processing of our water discharge permit applications, on thewest side of the basin, and in advance of the receipt of final requirements ofthe DEQ, we have installed and are evaluating various types of water treatmentfacilities to test their effectiveness. We are treating the water produced insome areas of the basin and, with the approval of the DEQ, discharging thiswater into the Powder River. We believe many of the future developments in theBig George coal will likely require water treatment facilities. These treatingoperations have added and will continue to add to the cost of development andoperations in these areas. We continue to evaluate several options for watertreatment and are working with the governmental agencies to identify effectiveand cost efficient methods. We are also evaluating the feasibility and cost ofinstalling and operating a water pipeline to transport and dispose of producedwater away from the development areas. Depending upon the type of watertreatment system that proves to be the most effective and cost efficient, wemay incur additional costs and/or delays in production and access to materialsrequired to deploy these facilities in all our operating areas.

 

Our 2006 capital budgetfor the Powder River Basin CBM project is approximately $282.2 million, ofwhich $136.7 million was expended in our March 2006 acquisition of properties. Theremaining $145.5 million is for drilling, production equipment, leaseholdacquisition and water treatment of approximately 900 gross wells. In 2006, inthe Big George and related coals, we plan to participate in the drilling ofapproximately 850 gross wells, or

 

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450 net wells, and in the Wyodak and related coals, we plan toparticipate in an additional 100 gross wells, or 50 net wells. Together withour co-developer, we have received 45% of the drilling permits and 54% of thewater discharge permits required for our drilling program for 2006. Theremainder of our 2006 federal and state permits required for our 2006 drillingprogram have been submitted to the respective agencies. There is, however, noassurance as to the future timing of the receipt of drilling and waterdischarge permits, any changes in regulations governing drilling and waterdischarge,  the success of our drillingprogram, the availability of materials used in water treatment, or thedewatering time as our development progresses into the western and northernparts of the Powder River Basin. During the first quarter of 2006, we expendedapproximately $168.6 million in the Powder River Basin CBM project for theMarch 2006 property acquisition, drilling costs, production equipment and otherlease acquisitions.

 

In 2003, the BLM issuedthe final Record of Decision, or ROD, for the Powder River Basin Oil & GasEnvironmental Impact Statement, or EIS. The ROD requires additional surveys forplant and animal species, cultural surveys and noxious weed mitigation prior tothe BLM granting a drilling permit. A number of cases have been filed byenvironmental groups against the BLM in Wyoming disputing the validity of theEIS and ROD. Due to our interests in developing federal leases in the PowderRiver Basin, we are an intervenor defendant in these cases. In one of thesecases filed in the United States District Court of Montana, the court was askedto address the adequacyof the Montana Powder River Basin ROD and whether the BLM should have issued asingle EIS for the Powder River Basin. Under an Order dated March 4, 2005, thecourt found that a single EIS for the Powder River Basin is not required underthe National Environmental Policy Act, or NEPA, but remanded the EIS back to the BLM for further analysis. Asthese cases proceed, the BLM, in the event of any adverse rulings, maybe required to perform further environmental analysis and, in addition, couldbe ordered to cease issuing drilling permits until it has completed suchfurther analysis. Consequently, our ability to receive permits and develop ourleases may be delayed or restricted by the outcome of these cases.

 

***Pinedale Anticline and Jonah Fields.***Ourexploration and production assets in the Green River Basin of southwest Wyomingare located in the Pinedale Anticline and Jonah Field areas. During 2006, weexpect to participate as a non-operating working interest in the drilling of132 gross wells, or approximately 15 net wells, on the Pinedale Anticline andin the Jonah Field. Our capital budget for 2006 in the Pinedale Anticline areaprovides for expenditures of approximately $78.2 million for drilling costs andproduction equipment. During the first quarter of 2006, we expendedapproximately $15.0 million in the Pinedale Anticline and Jonah Field fordrilling costs and production equipment.

 

Historically, drilling inthe Jonah Field and on the Pinedale Anticline has been allowed on one well per40-acre tract. More recently, the State of Wyoming has approved the drilling oftwo wells per 40-acre tract on most of the Pinedale Anticline and four wellsper 40-acre tract in the Jonah Field and on a portion of the Pinedale Anticline.As a result, we have significantly increased our number of drilling locationsin these areas. The BLM has also approved several 10 acre density well programson a pilot basis for the Pinedale Anticline.

 

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

#### ** **

Ourmidstream operations consist of our gathering, processing, treating, marketingand transportation operations. An important element of our long-term businessplan is to meet or exceed throughput projections in these areas and to optimizetheir profitability. To achieve this goal, we must continue our efforts to addto natural gas throughput levels through new well connections and through theexpansion or acquisition of gathering or processing systems. We also seek toincrease the efficiency of our operations by modernization of equipment and theconsolidation of existing facilities.

 

***Gas Gathering, Processing and Treating.***We operate avariety of gathering, processing and treating facilities, or plant operations,which are located in some of the most actively drilled oil and gas producing basins in theUnited States. Six of our processing plants can further separate, orfractionate, the mixed NGL stream into ethane, propane, normal butane andnatural gasoline to obtain a higher value for the NGLs, and three of our plantsare capable of processing and treating natural gas containing hydrogen sulfideor other impurities that require removal prior to delivery to market pipelines.In addition to our integrated upstream and midstream operations in the PowderRiver and Green River Basins in Wyoming, and in the San Juan Basin in NewMexico, ourcore assets include our plant operations located in west Texas and Oklahoma. Webelieve that our core assets have stable production rates, significant provenreserves connected to our systems, provide a significant operating cash flow andcontinue to provide us with strategic growth opportunities.

 

Our 2006 capital budgetfor midstream activities provides for expenditures of $185.0 million. This capital budget includes $61.1 million for gathering and compression in thePowder River Basin of Wyoming, $17.5 million for compression and loop lines toexpand the capacity of our Red Desert Complex, $24.6 million to complete the

 

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expansion of our Oklahoma system, and $32.1 million for new wellconnects to our facilities throughout our operations.

 

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

 

##### ***We own and operate MIGC, Inc., an interstate pipeline located in thePowder River Basin, and MGTC, Inc., an intrastate pipeline located in northeastWyoming. MIGC charges a Federal Energy Regulatory Commission, or FERC, approvedtariff and is connected to pipelines owned by Colorado Interstate Gas Company,Williston Basin Interstate Pipeline Company, Kinder Morgan Interstate PipelineCo., Wyoming Interstate Company, Ltd. and MGTC. MIGC earns fees on a monthlybasis from firm capacity contracts under which the shipper pays for transportcapacity, whether or not the capacity is used, and from interruptible contractswhere a fee is charged based upon volumes received into the pipeline. Contractswith third parties for capacity on MIGC range in duration from one month toapproximately five years, and the fees charged averaged $0.35 per Mcf in 2005. MGTC,a public utility, provides transportation and gas sales to various cities in Wyomingat rates that are subject to the approval of the Wyoming Public ServiceCommission.***

##### *** ***

***Marketing***

 

***Gas*.**We market gas produced from ourwells and gas processed at our plants, as well as gas purchased fromthird-parties to end-users, local distribution companies, or LDCs, pipelinesand other marketing companies throughout the United States and Canada. Inaddition to our offices in Denver, we have marketing offices in Houston, Texasand Calgary, Alberta. Third-party sales, firm transportation capacity oninterstate pipelines and our gas storage positions, combined with the stablesupply of gas from our facilities and production, enable us to respond quicklyto changing market conditions and to take advantage of seasonal pricevariations and peak demand periods.

 

One of the primary goalsof our gas marketing operations continues to be the preservation andenhancement of the value received for our equity volumes of natural gas. Thisgoal is achieved through the use of hedges on the production of our equity naturalgas and through the use of firm transportation capacity. Historically, the gasproduced in the Rocky Mountain region has traded at a substantial discount ascompared to the Mid-Continent and West Coast areas, as a result of limitedpipeline capacity from the region. We have historically used our firm pipelinetransportation capacity to access higher priced Mid-Continent markets for bothour equity production and for gas purchased from third-parties in the RockyMountain region.

 

***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 ourproduction of NGLs moves to the Gulf Coast and Mid-Continent areas, which arethe largest NGL markets in the United States. Through the development ofend-use markets and distribution capabilities, we seek to ensure that productsfrom our plants move on a reliable basis, avoiding curtailment of production.

 

Consumers of NGLs areprimarily the petrochemical industry, the petroleum refining industry and theretail and industrial fuel markets. As an example, the petrochemical industryuses ethane, propane, normal butane and natural gasoline as feedstocks in theproduction of ethylene, which is used in the production of various plastics andclothing products. Further, consumers use propane for home heating,transportation and agricultural applications. Price, seasonality and theeconomy primarily affect the demand for NGLs.

 

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**ITEM 3.****                             QUANTITATIVEAND QUALITATIVE DISCLOSURES ABOUT MARKET RISK**

 

Our commodity price riskmanagement program has two primary objectives. The first goal is to preserveand enhance the value of our equity volumes of gas and NGLs with regard to theimpact of commodity price movements on cash flow and net income in relation tothose anticipated by our operating budget. The second goal is to manage pricerisk related to our marketing activities to protect profit margins. This riskrelates to fixed price purchase and sale commitments, the value of storageinventories and exposure to physical market price volatility.

 

We utilize a combinationof fixed price forward contracts, exchange-traded futures and options, as wellas fixed index swaps, basis swaps and options traded in the over-the-counter,or OTC, market to accomplish these goals. These instruments allow us topreserve value and protect margins because corresponding losses or gains in thevalue of the financial instruments offset gains or losses in the physicalmarket.

 

We also use financialinstruments to reduce basis risk. Basis is the difference in price between thephysical commodity being hedged and the price of the futures contract used forhedging. Basis risk is the risk that an adverse change in the futures marketwill not be completely offset by an equal and opposite change in the cash priceof the commodity being hedged. Basis risk exists in natural gas primarily dueto the geographic price differentials between cash market locations and futurescontract delivery locations.

 

We enter into futurestransactions on the New York Mercantile Exchange, or NYMEX, and OTC swaps andoptions with various counterparties, consisting primarily of investment banks,financial institutions and other natural gas companies. We conduct creditreviews of all of our OTC counterparties and have agreements with many of theseparties that contain collateral requirements. We generally use standardizedswap agreements that allow for offset of positive and negative OTC exposureswith the same counterparty. OTC exposure is marked-to-market daily for thecredit review process. Our exposure to OTC credit risk is reduced by our abilityto require a margin deposit from our counterparties based upon themark-to-market value of their net exposure. We are also subject to margindeposit requirements under these same agreements and under margin depositrequirements for our NYMEX transactions.

 

We continually monitorand review the credit exposure to our marketing counterparties. In recentmonths the prices of natural gas and NGLs, and therefore our credit exposures,have increased significantly. Additionally, as a result of the damage in theGulf States caused by hurricanes Katrina and Rita, prices increased even moredramatically, and several of our counterparties experienced a significantamount of damage to their operating assets. In September 2005, one of ourcustomers, a utility serving the New Orleans area, filed for bankruptcyprotection under Chapter 11 of the Bankruptcy Code. At the time of thebankruptcy filing, we had an outstanding account receivable from this utilityof $4.1 million. In the third quarter of 2005, we reserved $800,000 againstthis amount, which represents our best estimate of the current market value ofthis receivable.

 

 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, negotiatedaccelerated payment terms with several customers, curtailed sales to certaincounterparties, and increased the amount of credit which we make available tosubstantial companies which meet our credit requirements. Although nettingagreements similar to those that we utilize have been upheld by bankruptcycourts in the past, if any of the customers with whom we have nettingagreements were to file for bankruptcy, we can provide no assurance that ouragreements will not be challenged or as to the outcome of any challenge.

 

The use of financialinstruments may expose us to the risk of financial loss in some circumstances,including instances when (i) our equity volumes are less than expected, (ii)our customers fail to purchase or deliver the contracted quantities of naturalgas or NGLs, or (iii) our OTC counterparties fail to perform. To the extentthat we engage in hedging activities, we may be prevented from realizing thebenefits of favorable price changes in the physical market. However, we aresimilarly insulated against decreases in these prices.

 

***Risk Policy and Control.***We controlthe extent of risk management and marketing activities through policies andprocedures that involve the senior level of management. On a daily basis, ourmarketing activities are audited and monitored by our independent riskoversight department, or IRO. This department reports to the Chief FinancialOfficer, thereby providing a separation of duties from the marketing department.Additionally, the IRO reports monthly to the Risk Management Committee, or RMC.This committee is comprised of corporate managers and officers and isresponsible for developing the policies and guidelines that control themanagement and measurement of risk, subject to the approval of the board ofdirectors. The RMC is also responsible for setting risk limits includingvalue-at-risk and dollar stop loss limits, subject to the approval of our boardof directors.

 

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***Hedge Positions.***Our hedge contractsare designated and accounted for as cash flow hedges. As such, gains and lossesrelated to the effective portions of the changes in the fair value of thederivatives are recorded in Accumulated other comprehensive income, a componentof Stockholders’ equity. Realized gains or losses on these cash flow hedges arerecognized in the Consolidated Statement of Operations through Sale of gas orSale of natural gas liquids when the hedged transactions occur.

 

Toqualify as cash flow hedges, the hedge instruments must be designated as cashflow hedges and changes in their fair value must be highly effective atoffsetting changes in the price of the forecasted transaction being hedged sothat our exposure to the risk of commodity price changes is reduced. To meetthis requirement, we hedge the price of the commodity and, if applicable, thebasis between that derivative’s contract delivery location and the cash marketlocation used for the actual sale of the product. This structure attains a highlevel of effectiveness, ensuring that a change in the price of the forecastedtransaction will result in an equal and opposite change in the price of thederivative instrument hedging the transaction. We utilize crude oil as a surrogatehedge for natural gasoline and condensate. Our hedges are tested foreffectiveness at inception and on a quarterly basis thereafter. We useregression analysis based on a five-year period of time for this test. Gains orlosses from the ineffective portions of changes in the fair value of cash flowhedges are recognized currently in earnings through Price risk managementactivities. During the first quarter of 2006, we recognized no gains or lossesfrom ineffectiveness from our cash flow hedges.

 

***Outstanding Equity Hedge Positions and the Associated Basisfor 2006 and 2007.***The following table details our hedgepositions as of March 31, 2006. In order to determine the hedged price to theparticular operating region, deduct the basis differential from the settleprice. There is no associated cost for the hedges.

 

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| **Product**        | ** ** | **Year**     | ** ** | **Quantity and Settle Price**                                                                                                                                                                                                                                                                                                                                                                               | ** ** | **Hedge of Basis Differential**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
|--------------------|------------|--------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| Natural gas        |       | 2006

  |       | 40,000 MMBtu per day  with an average minimum price of $6.00 per MMBtu and an average maximum price  of $10.13 per MMBtu.

 

45,000 MMBtu per day  with an average minimum price of $9.00 per MMBtu and an average maximum price  of $17.25 per MMBtu.

 

30,000 MMBtu per day  from April through December with an average minimum price of $7.00 per MMBtu  and an average maximum price of $10.25 per MMBtu |       | Mid-Continent – 40,000  MMBtu per day with an average basis price of $0.55 per MMBtu.

 

Permian – 7,500 MMBtu  per day with an average basis price of $0.97 per MMBtu.

 

San Juan – 7,500 MMBtu  per day with an average basis price of $1.38 per MMBtu and 5,000 MMBtu per  day from April through December with an average basis price of $1.70 per  MMBtu.

 

Rocky Mountain – 20,000  MMBtu per day with an average basis price of $1.44 per MMBtu and 5,000 MMBtu  per day from April through December with an average basis price of $1.71 per  MMBtu.

 

NGPL  Texas Oklahoma – 10,000 MMBtu per day with  an average basis price of $0.45 per MMBtu and 20,000 MMBtu per day from April  through December with an average basis price of $0.55 per MMBtu

  |
|               |       | 2007         |       | 115,000 MMBtu per day  with an average minimum price of $7.00 per MMBtu and an average maximum price  of $14.90 per MMBtu.

 

                                                                                                                                                                                                                                                                                  |       | Mid-Continent – 20,000  MMBtu per day with an average basis price of $0.98 per MMBtu.

 

Permian – 10,000 MMBtu  per day with an average basis price of $1.20 per MMBtu.

 

San Juan – 10,000 MMBtu  per day with an average basis price of $1.77 per MMBtu.

 

Rocky Mountain – 45,000  MMBtu per day with an average basis price of $2.01 per MMBtu.

 

NGPL  Texas Oklahoma – 30,000 MMBtu per day with  an average basis price of $0.55 per MMBtu.

                                                                                                                                                                                                                                                                                                              |
| Natural   Gasoline |       | 2006         |       | 25,000 Barrels per  month with an average minimum price of $40.00 per barrel and an average  maximum price of $70.00 per barrel.                                                                                                                                                                                                                                                                                           |       | Not Applicable

 

                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| Ethane             |       | 2006         |       | 200,000 Barrels per  month for April through December with an average minimum price of $0.51 per  gallon and an average maximum price of $0.67 per gallon.                                                                                                                                                                                                                                                                 |       | Not Applicable

 

                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| Propane            |       | 2006         |       | 140,000 Barrels per month  for April through December with an average minimum price of $0.83 per gallon  and an average maximum price of $1.04 per gallon.                                                                                                                                                                                                                                                                 |       | Not Applicable

 

                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |

 

33

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Account balances relatedto hedging transactions (designated as cash flow hedges under SFAS 133) atMarch 31, 2006 were $29.0 million in Current assets from price risk managementactivities, $4.9 million in Long term assets from price risk managementactivities, $3.2 million in Current liabilities from price risk managementactivities, $11.2 million in Deferred income tax payable, net, and a $19.5million after-tax unrealized gain in Accumulated other comprehensive income, acomponent of Stockholders’ equity. Of the unrealized gain in Accumulated othercomprehensive income at March 31, 2006, $16.3 million will be reclassified toearnings in 2006 and $3.2 million will be reclassified to earnings in 2007.

 

***Earnings Sensitivities.***At March 31,2006, we held gas in our contracted storage facilities and in imbalances ofapproximately 14.0 Bcf. This inventoried gas was sold forward. Based on a $1.00increase in the forward price of gas in the anticipated month of withdrawal,the change in the non-cash mark-to-market value of these derivatives woulddecrease pre-tax earnings by $14.0 million and a $1.00 decrease in the forwardprice of gas in the anticipated month of withdrawal would increase pre-taxearnings by $14.0 million. As the stored or transported natural gas is sold andthe future sale derivatives are settled, we will realize the benefit of thestorage and transportation transactions through earnings and Net cash fromoperating activities.

 

As of March 31, 2006, wehad sold basis swaps for 115,000 MMBtu per day at various sales points for2008, at an average differential of $1.16. These positions will minimize ourprice risk as it relates to the change in the basis differential from NYMEX toour various sales points. As we did not sell forward our equity natural gas inconjunction with these basis transactions, these positions are not eligible forhedge accounting treatment. Accordingly, these transactions will bemarked-to-market through Price risk management activities. Based on a $0.10increase in the forward basis differential in the anticipated month of sale,the change in the non-cash mark-to-market value of these derivatives wouldincrease pre-tax earnings by $4.2 million and a $0.10 decrease in the forwardbasis differential in the anticipated month of sale would decrease pre-taxearnings by $4.2 million. As our equity gas is sold and the future basisderivatives are settled, we will realize the economic effect of thesetransactions through earnings and Net cash from operating activities.

 

***Summary of Derivative Positions.***Asummary of the net change in our derivative position from December 31, 2005 toMarch 31, 2006 is as follows (dollars in thousands):

 
| Fair value of  contracts outstanding at December 31, 2005              |   | $       | 20,140 |   |
|------------------------------------------------------------------------|--------|---------|--------|--------|
| Increase in  value due to change in price                              |   | 61,728  |   |
| Increase in  value due to new contracts entered into during the period |   | 16,930  |   |
| Contract  settlements during the period                                |   | (48,600 | )      |
| Changes in fair  value attributable to changes in valuation techniques |   | —  |   |
| Fair value of  contracts outstanding at March 31, 2006                 |   | $       | 50,198 |   |

 

A summary of the sourcesof fair value of our net outstanding derivative positions at March 31, 2006 isas follows (dollars in thousands):

 
| ** **                              | ** ** | **Fair Value of Contracts at March 31, 2006** | ** ** |
|-----------------------------------------|------------|----------------------------------------------------------------------------------|------------|
| **Source of Fair Value** | ** ** | **Total  Fair Value**                                                       | ** ** | **Maturing  In 2006** | ** ** | **Maturing In  2007-2008** | ** ** | **Maturing In  2009-2010** | ** ** | **Maturing  Thereafter** | ** ** |
| Exchange  published prices              |       | $                                                                                | 6,515      |   | $ | 5,656 |   | $ | 859 |   | — |   | — |   |
| Other actively  quoted prices (1)       |       | 29,498                                                                           |       | 21,415 |   | 8,083 |   | $ | — |   | — |   |
| Other valuation  methods (2)            |       | 14,185                                                                           |       | 13,064 |   | 1,121 |   | — |   | — |   |
| Total fair value                        |       | $                                                                                | 50,198     |   | $ | 40,135 |   | $ | 10,063 |   | $ | — |   | — |   |

 

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(1)          Other actively quotedprices are derived from broker quotations, trade publications, and industryindices.

 

(2)          Other valuation methodsare the Black-Scholes option-pricing model utilizing prices and volatilityobtained from broker quotations, trade publications, and industry indices.

 

***Foreign Currency Derivative Market Risk***. As anormal part of our business, we enter into physical gas transactions which arepayable 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 marketing margins from adverse changes inthe United States and Canadian dollar exchange rate between the time thecommitment for the payment obligation is made and the actual payment date ofsuch obligation. As of March 31, 2006, we had sold forward contracts for $40.6million in Canadian dollars in exchange for $35.5 million in United Statesdollars, and the fair market value of these contracts was a gain of $285,500 inUnited States dollars.

 

34

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**ITEM 4.  CONTROLS ANDPROCEDURES**

 

***Disclosure Controlsand Procedures.***

 

Our management evaluated,under the supervision of and with the participation of the Chief ExecutiveOfficer and Chief Financial Officer, the effectiveness of our disclosurecontrols and procedures, as such term is defined under Rule 13a-15(e) under theSecurities Exchange Act of 1934, as of the end of the period covered by thisReport. Based on this evaluation, the Chief Executive Officer and ChiefFinancial Officer have concluded that our disclosure controls and procedureswere effective as of March 31, 2006, to ensure that information we are requiredto disclose in reports that we file or submit under the Securities Exchange Actof 1934 is recorded, processed, summarized and reported within the time periodsspecified in Securities and Exchange Commission rules and forms and that suchinformation is accumulated and communicated to our management, including ourChief Executive Officer and Chief Financial Officer, as appropriate, to allowtimely decisions regarding required disclosures.

 

***Changes in InternalControls over Financial Reporting.***

 

Therehave not been any changes in our internal control over financial reportingduring the quarter ended March 31, 2006, that have materially affected, or arereasonably likely to materially affect, our internal control over financialreporting.

 

35

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**PARTII - OTHER INFORMATION**

 

**ITEM 1.    LEGAL PROCEEDINGS**

 

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

 

**ITEM6.    EXHIBITS**

 
| **Exhibit** | ** ** | ** **                                                                                                                                                                                                                                               |
|-------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| **Number**  | ** ** | **Description**                                                                                                                                                                                                                                          |
|        |       |                                                                                                                                                                                                                                                     |
| 3.1         |       | Certificate  of Incorporation of Western Gas Resources, Inc. (previously filed as Exhibit  3.1 to our Registration Statement on Form S-1, Registration No. 33-31604 and  incorporated herein by reference).                                              |
|        |       |                                                                                                                                                                                                                                                     |
| 3.2         |       | Certificate  of Amendment to the Certificate of Incorporation of Western Gas Resources,  Inc. (previously filed as Exhibit 3.2 to our Registration Statement on Form  S-1, Registration No. 33-31604 and incorporated herein by reference).              |
|        |       |                                                                                                                                                                                                                                                     |
| 3.3         |       | Certificate of  Designation, Preferences and Rights of Series A Junior Participating  Preferred Stock (previously filed as part of Exhibit 1 to our Form 8-A filed  on March 30, 2001 and incorporated herein by reference).                             |
|        |       |                                                                                                                                                                                                                                                     |
| 3.4         |       | Amended and Restated  Bylaws of Western Gas Resources, Inc. adopted by the Board of Directors on  January 13, 2006 (previously filed as Exhibit 3.01 to our Current Report on  Form 8-K filed on January 19, 2006 and incorporated herein by reference). |
|        |       |                                                                                                                                                                                                                                                     |
| 31.1        |       | Section 302  Certification of the Chief Executive Officer.                                                                                                                                                                                          |
|        |       |                                                                                                                                                                                                                                                     |
| 31.2        |       | Section 302  Certification of the Chief Financial Officer.                                                                                                                                                                                          |
|        |       |                                                                                                                                                                                                                                                     |
| 32.1        |       | Section 906  Certification of the Chief Executive Officer and Chief Financial Officer.                                                                                                                                                              |

 

36

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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.

 
| Date: May 9, 2006 | WESTERN GAS RESOURCES,  INC. |                                                 |
|-------------------|------------------------------|------------------------------------------------------|
|              | (Registrant)                 |
|              |                         |                                                 |
|              |                         |                                                 |
|              | By:                          | /s/ PETER A. DEA                                     |   |
|              |                         | Peter A. Dea                                         |
|              |                         | Chief Executive Officer  and President               |
|              |                         |                                                 |
|              |                         |                                                 |
| Date: May 9, 2006 | By:                          | /s/WILLIAM J. KRYSIAK                                |   |
|              |                         | William J. Krysiak                                   |
|              |                         | Executive Vice  President - Chief Financial  Officer |
|              |                         | (Principal Financial  and Accounting  Officer)       |
|                   |                              |                                                      |  |  |

 

37

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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  January 13, 2006 (previously filed as Exhibit 3.01 to our Current Report on  Form 8-K filed on January 19, 2006 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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