**SECURITIESAND EXCHANGE COMMISSION**

 

**Washington, D.C. 20549**

 

### **FORM 10-Q/A**

### ** **

**(Amendment No. 1)**

 

**(MarkOne)**

 
| **ý**                                                                                                                                                                                                                                                         | **QUARTERLY REPORT PURSUANT TO  SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**  |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------|
|                                                                                                                                                                                                                                                               |                                                                                                    |
| **FOR THE  QUARTERLY PERIOD ENDED JUNE 30, 2005**                                                                                                                                                                                                             |
| ** **                                                                                                                                                                                                                                                         |
| **OR**                                                                                                                                                                                                                                                             |
|                                                                                                                                                                                                                                                               |                                                                                                    |
| **o**                                                                                                                                                                                                                                                              | **TRANSITION REPORT PURSUANT TO  SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934** |
|                                                                                                                                                                                                                                                               |                                                                                                    |
| **FOR THE TRANSITION PERIOD FROM                      TO                    ** |

 

**Commission file number 1-10389**

 

### **WESTERNGAS RESOURCES, INC.**

(Exact name of registrant as specified in its charter)

 
| **Delaware**                                       | ** ** | **84-1127613**      |
|----------------------------------------------------|------------|---------------------|
| (State or other jurisdiction of                    |       | (I.R.S. Employer    |
| incorporation or organization)                     |       | Identification No.) |
|                                               |       |                |
| **1099 18th Street, Suite 1200, Denver, Colorado** |       | **80202**           |
| (Address of principal executive offices)           |       | (Zip Code)          |

 

**(303) 452-5603**

Registrant’s telephone number, including area code

 

**No Changes**

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

 

Indicate by check markwhether the registrant (1) has filed all reports required to be filed by Section 13or 15(d) of the Securities Exchange Act of 1934 during the preceding 12months (or for such shorter period that the registrant was required to filesuch reports), and (2) has been subject to such filing requirements forthe past 90 days. Yes ý  No o

 

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

 

On August 5, 2005,there were 74,617,902 shares of the registrant’s Common Stock outstanding.

 

###### * *

----

 

###### *Explanatory Note*

###### * *

OurQuarterly Report on Form 10-Q for the quarter ended June 30, 2005,initially filed with the Securities and Exchange Commission, or the SEC, on August 9, 2005,or the Original Filing, is being amended by this Form 10-Q/A to reflectrestatements of our Consolidated balance sheet at June 30, 2005 and December 31,2004; and our Consolidated Statement of Operations, Consolidated Statement ofCash Flows and Consolidated Statement of Changes in Stockholders’ Equity foreach of the quarters and six months ended June 30, 2005 and 2004, andthe notesthereto.

 

Upon adoption of FASBStatement No. 133, “Accounting for Derivative Instruments and HedgingActivities” (“FAS 133”)in 2001, we analyzed our gas storage and gas transportation contracts indetail, and determined that these contracts had the characteristics of aderivative as described in FAS 133.  Thetreatment of these contracts as derivatives has been consistently applied sinceadoption of FAS 133 as reflected in our consolidated financial statements.  Historically, we recorded these contracts atfair value with the changes in fair value reflected in earnings. On November 8,2005, after the release of our third quarter 2005 results and prior to thefiling of the Form 10-Q for the quarter ended September 30, 2005, itcame to our attention that these contracts may not meet the definition of aderivative.  On November 21, 2005, we announced that our managementand our audit committee had completed a review of the accounting treatment ofour gas storage and gas transportation contracts and determined that thesecontracts do not meet the definition of a derivative under generally acceptedaccounting principles. Specifically, after a detailed review of the contractsand the market for those contracts, we determined that these contracts do notmeet the definition of a derivative as: (i) the market for these types ofcontracts is not sufficiently liquid for us to receive fair value in a readymarket and (ii) if any contract is assigned, there is no assurance that wewill be relieved of our rights and obligations under that contract.

 

For a more detailed description of these restatements,see the footnote “Restatement of Consolidated Financial Statements” to theaccompanying Consolidated Financial Statements and the section entitled “Restatement”in Management’s Discussion and Analysis of Financial Condition and Results ofOperations contained in this Form 10-Q/A.

 

Except for the foregoing amended information, this Form 10-Q/Acontinues to describe conditions as of the date of the Original Filing,including our expectations with respect to our 2005 capital budget and otherforward-looking information, and we have not updated the disclosures containedherein to reflect events that occurred at a later date. Other events occurringafter the filing of the Original Filing or other disclosures necessary toreflect subsequent events have been or will be addressed in either our restatedQuarterly Report on Form 10-Q for the quarterly period ended September 30, 2005,which is being filed concurrently with the filing of this Form 10-Q/A, or inother reports filed with the SEC subsequent to the date of this filing.

 

2

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**Western Gas Resources, Inc.**

**Form 10-Q/A**

**Table of Contents**

 
| PART I - Financial Information |                                                                                                  |
|-------------------------------------|-------------------------------------------------------------------------------------------------------|
|                                |                                                                                                  |   |
|                                | Explanatory Note                                                                                      |   |
|                                |                                                                                                  |   |
| Item 1.                             | Financial Statements                                                                                  |   |
|                                |                                                                                                  |   |
|                                | Consolidated Balance Sheet -  June 30, 2005 and December 31, 2004                           |   |
|                                |                                                                                                  |   |
|                                | Consolidated Statement of  Cash Flows - Six Months Ended June 30, 2005 and 2004                  |   |
|                                |                                                                                                  |   |
|                                | Consolidated Statement of  Operations – Three and Six Months Ended June 30, 2005 and 2004   |   |
|                                |                                                                                                  |   |
|                                | Consolidated Statement of  Changes in Stockholders’ Equity - Six Months Ended June 30, 2005 |   |
|                                |                                                                                                  |   |
|                                | Notes to Consolidated  Financial Statements                                                           |   |
|                                |                                                                                                  |   |
| Item 2.                             | Management’s Discussion and Analysis  of Financial Condition and Results of Operations           |   |
|                                |                                                                                                  |   |
| Item 3.                             | Quantitative and Qualitative  Disclosures about Market Risk                                           |   |
|                                |                                                                                                  |   |
| Item 4.                             | Controls and Procedures                                                                               |   |
|                                |                                                                                                  |   |
| PART II - Other  Information   |                                                                                                  |
|                                |                                                                                                  |   |
| Item 1.                             | Legal Proceedings                                                                                     |   |
|                                |                                                                                                  |   |
| Item 4.                             | Submission of Matters to a Vote of  Security Holders                                                  |   |
|                                |                                                                                                  |   |
| Item 6.                             | Exhibits                                                                                              |   |
|                                |                                                                                                  |   |
| Signatures                          |                                                                                                  |   |

 

3

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**PART I- FINANCIAL INFORMATION**

 

**ITEM1.       FINANCIAL STATEMENTS**

** **

WESTERN GAS RESOURCES,INC.

CONSOLIDATED BALANCESHEET

(Unaudited)

(Dollars in thousands,except share data)

 
| ** **                                                                                                           | ** ** | **June 30,** | ** ** | **December 31,** | ** ** |
|----------------------------------------------------------------------------------------------------------------------|------------|-------------------|------------|-----------------------|------------|
| ** **                                                                                                           | ** ** | **2005**          | ** ** | **2004**              | ** ** |
| ** **                                                                                                           | ** ** | **Restated**      | ** ** | **Restated**          | ** ** |
| ASSETS                                                                                                               |       |              |       |                  |       |
|                                                                                                                 |       |              |       |                  |       |
| Current assets:                                                                                                      |       |              |       |                  |       |
| Cash and cash  equivalents                                                                                           |       | $                 | 6,038      |                  | $          | 390 |   |
| Trade accounts  receivable, net                                                                                      |       | 314,415           |       | 385,811               |       |
| Margin deposits                                                                                                      |       | 16,885            |       | 7,939                 |       |
| Product  inventory                                                                                                   |       | 92,096            |       | 94,604                |       |
| Assets from  price risk management activities                                                                        |       | 5,970             |       | 19,893                |       |
| Deferred income  tax                                                                                                 |       | 3,399             |       | —                |       |
| Other                                                                                                                |       | 11,766            |       | 12,494                |       |
| Total current  assets                                                                                                |       | 450,569           |       | 521,131               |       |
| Property  and equipment:                                                                                             |       |              |       |                  |       |
| Gas gathering,  processing and transportation                                                                        |       | 1,215,286         |       | 1,150,904             |       |
| Oil and gas  properties and equipment (successful efforts method)                                                    |       | 549,715           |       | 495,314               |       |
| Construction in  progress                                                                                            |       | 219,866           |       | 150,273               |       |
|                                                                                                                 |       | 1,984,867         |       | 1,796,491             |       |
| Less:  Accumulated depreciation, depletion and amortization                                                          |       | (620,606          | )          | (570,582              | )          |
|                                                                                                                 |       |              |       |                  |       |
| Total property  and equipment, net                                                                                   |       | 1,364,261         |       | 1,225,909             |       |
| Other  assets:                                                                                                       |       |              |       |                  |       |
| Gas purchase  contracts (net of accumulated amortization of $41,606 and  $40,652, respectively)                 |       | 33,044            |       | 27,704                |       |
| Assets from  price risk management activities                                                                        |       | 540               |       | 249                   |       |
| Equity  investments                                                                                                  |       | 36,084            |       | 35,729                |       |
| Other                                                                                                                |       | 25,796            |       | 26,676                |       |
|                                                                                                                 |       |              |       |                  |       |
| Total other  assets                                                                                                  |       | 95,464            |       | 90,358                |       |
|                                                                                                                 |       |              |       |                  |       |
| TOTAL ASSETS                                                                                                         |       | $                 | 1,910,294  |                  | $          | 1,837,398 |   |
|                                                                                                                      |       |              |       |                  |       |
| LIABILITIES AND  STOCKHOLDERS’ EQUITY                                                                           |       |              |       |                  |       |
|                                                                                                                 |       |              |       |                  |       |
| Current liabilities:                                                                                                 |       |              |       |                  |       |
| Accounts payable                                                                                                     |       | $                 | 357,560    |                  | $          | 400,672 |   |
| Accrued expenses                                                                                                     |       | 57,541            |       | 60,472                |       |
| Liabilities from  price risk management activities                                                                   |       | 15,391            |       | 4,321                 |       |
| Deferred income  tax                                                                                                 |       | —            |       | 5,618                 |       |
| Dividends  payable                                                                                                   |       | 3,733             |       | 3,704                 |       |
| Total current  liabilities                                                                                           |       | 434,225           |       | 474,787               |       |
| Long-term  debt                                                                                                      |       | 417,000           |       | 382,000               |       |
| Liabilities from price risk management activities                                                                    |       | 1,436             |       | 180                   |       |
| Other long-term liabilities                                                                                          |       | 59,325            |       | 51,827                |       |
| Deferred income taxes payable, net                                                                                   |       | 265,947           |       | 243,835               |       |
|                                                                                                                 |       |              |       |                  |       |
| Total liabilities                                                                                                    |       | 1,177,933         |       | 1,152,629             |       |
|                                                                                                                 |       |              |       |                  |       |
| Stockholders’ equity:                                                                                           |       |              |       |                  |       |
| Common stock,  par value $.10; 100,000,000 shares authorized; 74,612,053 and 74,078,733  shares issued, respectively |       | 7,483             |       | 7,430                 |       |
| Treasury stock,  at cost; 50,032 common shares in treasury                                                           |       | (788              | )          | (788                  | )          |
| Unearned  compensation                                                                                               |       | (10,741           | )          | —                |       |
| Additional  paid-in capital                                                                                          |       | 407,693           |       | 392,437               |       |
| Retained  earnings                                                                                                   |       | 331,339           |       | 281,428               |       |
| Accumulated  other comprehensive income                                                                              |       | (2,625            | )          | 4,262                 |       |
|                                                                                                                 |       |              |       |                  |       |
| Total  stockholders’ equity                                                                                     |       | 732,361           |       | 684,769               |       |
|                                                                                                                 |       |              |       |                  |       |
| TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY                                                                      |       | $                 | 1,910,294  |                  | $          | 1,837,398 |   |

 

The accompanying notesare an integral part of the consolidated financial statements.

 

4

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WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OFCASH FLOWS

(Unaudited)

(Dollars in thousands)

 
| ** **                                                                              | ** ** | **Six Months Ended** | ** ** |
|-----------------------------------------------------------------------------------------|------------|----------------------|------------|
| ** **                                                                              | ** ** | **June 30,**    | ** ** |
| ** **                                                                              | ** ** | **2005**             | ** ** | **2004** | ** ** |
|                                                                                    |       |                 |       |   |   |
| Reconciliation  of net income to net cash provided by operating activities:             |       |                 |       |   |   |
| Net income                                                                              |       | $                    | 57,335     |   | $ | 48,083 |   |
| Add income items  that do not affect cash:                                              |       |                 |       |   |   |
| Depreciation,  depletion and amortization                                               |       | 59,877               |       | 44,974 |   |
| Loss on sale of  assets                                                                 |       | 27                   |       | 1,639 |   |
| Deferred income  taxes                                                                  |       | 19,775               |       | 27,068 |   |
| Non-cash change  in fair value of derivatives                                           |       | 17,614               |       | (3,303 | ) |
| Cumulative  effect of a change in accounting principle                                  |       | —               |       | (4,714 | ) |
| Compensation  expense from common stock options and restricted stock                    |       | 926                  |       | 476 |   |
| Other non-cash  items, net                                                              |       | (1,532               | )          | 1,815 |   |
|                                                                                    |       |                 |       |   |   |
| Adjustments to  working capital to arrive at net cash provided by operating activities: |       |                 |       |   |   |
| (Increase)  decrease in trade accounts receivable                                       |       | 71,601               |       | (23,972 | ) |
| (Increase)  decrease in margin deposits                                                 |       | (8,946               | )          | 1,956 |   |
| (Increase)  decrease in product inventory                                               |       | 1,933                |       | (3,008 | ) |
| Increase in  other current assets                                                       |       | (11,379              | )          | (3,856 | ) |
| (Increase)  decrease in other assets and liabilities, net                               |       | (565                 | )          | 322 |   |
| Increase  (decrease) in accounts payable                                                |       | (57,156              | )          | 2,975 |   |
| Increase  (decrease) in accrued expenses                                                |       | 10,592               |       | (2,323 | ) |
|                                                                                    |       |                 |       |   |   |
| Net cash provided by operating activities                                               |       | 160,102              |       | 88,132 |   |
|                                                                                    |       |                 |       |   |   |
| Cash flows from  investing activities:                                                  |       |                 |       |   |   |
|                                                                                    |       |                 |       |   |   |
| Purchases of  property and equipment, including acquisitions                            |       | (193,112             | )          | (79,548 | ) |
| Distributions  from equity investees                                                    |       | 613                  |       | 1,196 |   |
| Proceeds from  the dispositions of property and equipment                               |       | 1,411                |       | 697 |   |
|                                                                                    |       |                 |       |   |   |
| Net cash used in  investing activities                                                  |       | (191,088             | )          | (77,655 | ) |
|                                                                                    |       |                 |       |   |   |
| Cash flows from  financing activities:                                                  |       |                 |       |   |   |
|                                                                                    |       |                 |       |   |   |
| Proceeds from  exercise of common stock options                                         |       | 2,735                |       | 3,492 |   |
| Change in  outstanding checks                                                           |       | 6,335                |       | 26,168 |   |
| Borrowings under  revolving credit facility                                             |       | 1,789,015            |       | 810,630 |   |
| Payments on  revolving credit facility                                                  |       | (1,754,015           | )          | (809,630 | ) |
| Borrowings of  long-term debt                                                           |       | 25,000               |       | 100,000 |   |
| Payments on  long-term debt                                                             |       | (25,000              | )          | (155,000 | ) |
| Debt issue costs  paid                                                                  |       | (40                  | )          | (1,827 | ) |
| Payments for the  redemption of preferred stock                                         |       | —               |       | (1,930 | ) |
| Dividends paid                                                                          |       | (7,396               | )          | (5,610 | ) |
|                                                                                    |       |                 |       |   |   |
| Net cash  provided by (used in) financing activities                                    |       | 36,634               |       | (33,707 | ) |
|                                                                                    |       |                 |       |   |   |
| Net increase  (decrease) in cash and cash equivalents                                   |       | 5,648                |       | (23,230 | ) |
|                                                                                    |       |                 |       |   |   |
| Cash and cash  equivalents at beginning of period                                       |       | 390                  |       | 26,116 |   |
|                                                                                    |       |                 |       |   |   |
| Cash and cash  equivalents at end of period                                             |       | $                    | 6,038      |   | $ | 2,886 |   |

 

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

 

5

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WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OFOPERATIONS

(Unaudited)

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

 

 
| ** **                                                                                        | ** ** | **Three Months Ended** | ** ** | **Six Months Ended** | ** ** |
|---------------------------------------------------------------------------------------------------|------------|------------------------|------------|----------------------|------------|
| ** **                                                                                        | ** ** | **June 30,**      | ** ** | **June 30,**    | ** ** |
| ** **                                                                                        | ** ** | **2005**               | ** ** | **2004**             | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                                        | ** ** | **Restated**           | ** ** | **Restated**         | ** ** | **Restated** | ** ** | **Restated** | ** ** |
| Revenues:                                                                                         |       |                   |       |                 |       |   |   |   |   |
| Sale of gas                                                                                       |       | $                      | 678,087    |                 | $          | 595,881 |   | $ | 1,374,306 |   | $ | 1,261,191 |   |
| Sale of natural  gas liquids                                                                      |       | 149,481                |       | 102,021              |       | 282,450 |   | 194,936 |   |
| Gathering,  processing and transportation revenue                                                 |       | 27,823                 |       | 24,410               |       | 51,703 |   | 41,239 |   |
| Price risk  management activities                                                                 |       | 11,205                 |       | 2,995                |       | (9,043 | ) | 5,979 |   |
| Other                                                                                             |       | 1,430                  |       | 531                  |       | 2,717 |   | 2,173 |   |
| Total revenues                                                                                    |       | 868,026                |       | 725,838              |       | 1,702,133 |   | 1,505,518 |   |
|                                                                                              |       |                   |       |                 |       |   |   |   |   |
| Costs and  expenses:                                                                              |       |                   |       |                 |       |   |   |   |   |
| Product  purchases                                                                                |       | 707,516                |       | 602,166              |       | 1,414,870 |   | 1,259,508 |   |
| Plant and  transportation operating expense                                                       |       | 26,831                 |       | 22,255               |       | 54,530 |   | 44,189 |   |
| Oil and gas  exploration and production expense                                                   |       | 24,059                 |       | 19,812               |       | 48,955 |   | 36,922 |   |
| Depreciation,  depletion and amortization                                                         |       | 30,799                 |       | 22,348               |       | 59,877 |   | 44,974 |   |
| (Gain) loss on  sale of assets                                                                    |       | (1                     | )          | 1,639                |       | 27 |   | 1,639 |   |
| Selling and  administrative expense                                                               |       | 17,537                 |       | 17,255               |       | 30,069 |   | 27,201 |   |
| (Earnings) from  equity investments                                                               |       | (2,246                 | )          | (1,776               | )          | (4,380 | ) | (3,702 | ) |
| Loss from early  extinguishment of debt                                                           |       | —                 |       | 10,662               |       | — |   | 10,662 |   |
| Interest expense                                                                                  |       | 4,033                  |       | 5,351                |       | 7,553 |   | 11,153 |   |
| Total costs and  expenses                                                                         |       | 808,528                |       | 699,712              |       | 1,611,501 |   | 1,432,546 |   |
|                                                                                              |       |                   |       |                 |       |   |   |   |   |
| Income before  taxes                                                                              |       | 59,498                 |       | 26,126               |       | 90,632 |   | 72,972 |   |
| Provision for  income taxes:                                                                      |       |                   |       |                 |       |   |   |   |   |
| Current                                                                                           |       | 6,172                  |       | (1,008               | )          | 13,522 |   | 2,535 |   |
| Deferred                                                                                          |       | 15,697                 |       | 13,485               |       | 19,775 |   | 27,068 |   |
| Total provision  for income taxes                                                                 |       | 21,869                 |       | 12,477               |       | 33,297 |   | 29,603 |   |
|                                                                                              |       |                   |       |                 |       |   |   |   |   |
| Income before  cumulative effect of change in accounting principle                                |       | 37,629                 |       | 13,649               |       | 57,335 |   | 43,369 |   |
|                                                                                              |       |                   |       |                 |       |   |   |   |   |
| Cumulative  effect of change in accounting principle, net of tax of $2,710                        |       | —                 |       | —               |       | — |   | 4,714 |   |
|                                                                                              |       |                   |       |                 |       |   |   |   |   |
| Net income                                                                                        |       | 37,629                 |       | 13,649               |       | 57,335 |   | 48,083 |   |
|                                                                                              |       |                   |       |                 |       |   |   |   |   |
| Preferred stock  requirements                                                                     |       | —                 |       | (19                  | )          | — |   | (835 | ) |
|                                                                                              |       |                   |       |                 |       |   |   |   |   |
| Income  attributable to common stock                                                              |       | $                      | 37,629     |                 | $          | 13,630 |   | $ | 57,335 |   | $ | 47,248 |   |
|                                                                                              |       |                   |       |                 |       |   |   |   |   |
| Net income per  share of common stock before cumulative effect of change in accounting  principle |       | $                      | .51        |                 | $          | .19 |   | $ | .77 |   | $ | .60 |   |
|                                                                                              |       |                   |       |                 |       |   |   |   |   |
| Cumulative  effect of change in accounting principle                                              |       | $                      | —     |                 | $          | — |   | $ | — |   | $ | .07 |   |
|                                                                                              |       |                   |       |                 |       |   |   |   |   |
| Earnings per  share of common stock                                                               |       | $                      | .51        |                 | $          | .19 |   | $ | .77 |   | $ | .67 |   |
|                                                                                              |       |                   |       |                 |       |   |   |   |   |
| Weighted average  shares of common stock outstanding                                              |       | 74,234,424             |       | 73,158,240           |       | 74,191,346 |   | 70,942,578 |   |
|                                                                                              |       |                   |       |                 |       |   |   |   |   |
| Income  attributable to common stock – assuming dilution                                     |       | $                      | 37,629     |                 | $          | 13,649 |   | $ | 57,335 |   | $ | 47,248 |   |
|                                                                                              |       |                   |       |                 |       |   |   |   |   |
| Earnings per share of common stock – assuming dilution                                       |       | $                      | .50        |                 | $          | .18 |   | $ | .76 |   | $ | .65 |   |
|                                                                                              |       |                   |       |                 |       |   |   |   |   |
| Weighted average  shares of common stock outstanding assuming dilution                            |       | 75,678,389             |       | 75,329,143           |       | 75,603,310 |   | 72,820,040 |   |

 

The accompanying notesare an integral part of the consolidated financial statements.

 

6

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WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OFCHANGES 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** | ** ** | **Unearned**     | ** ** | **Paid-In**    | ** ** | **Retained** | ** ** | **Income  (Loss)** | ** ** | **holders’** | ** ** |
| ** **                                                  | ** ** | **Stock**      | ** ** | **in  Treasury** | ** ** | **Stock**  | ** ** | **Stock**    | ** ** | **Compensation** | ** ** | **Capital**    | ** ** | **Earnings** | ** ** | **Net of  Tax**    | ** ** | **Equity**        | ** ** |
|                                                        |       |           |       |             |       |       |       |         |       |             |       |           |       |         |       |               |       |              |       |
| Balance at  December 31, 2004 (restated)               |       | 74,078,733     |       | 50,032           |       | $          | 7,430      |         | $          | (788             | )          | $              | —     |         | $          | 392,437            |       | $                 | 281,428    |   | $ | 4,262 |   | $ | 684,769 |   |
| Comprehensive  income:                                      |       |           |       |             |       |       |       |         |       |             |       |           |       |         |       |               |       |              |       |
| Net income  (restated)                                      |       | —         |       | —           |       | —     |       | —       |       | —           |       | —         |       | 57,335       |       | —             |       | 57,335            |       |
| Translation  adjustments                                    |       | —         |       | —           |       | —     |       | —       |       | —           |       | —         |       | —       |       | (2,510             | )          | (2,510            | )          |
| Other  comprehensive income                                 |       |           |       |             |       |       |       |         |       |             |       |           |       |         |       |               |       |              |       |
| From equity  investees                                      |       | —         |       | —           |       | —     |       | —       |       | —           |       | —         |       | —       |       | 77                 |       | 77                |       |
| Reclassification  adjustment for settled contracts          |       | —         |       | —           |       | —     |       | —       |       | —           |       | —         |       | —       |       | (623               | )          | (623              | )          |
| Changes in fair  value of outstanding hedge  positions |       | —         |       | —           |       | —     |       | —       |       | —           |       | —         |       | —       |       | (2,339             | )          | (2,339            | )          |
| Change in  estimated ineffectiveness                        |       | —         |       | —           |       | —     |       | —       |       | —           |       | —         |       | —       |       | 79                 |       | 79                |       |
| Fair value of new  hedge positions                          |       | —         |       | —           |       | —     |       | —       |       | —           |       | —         |       | —       |       | (1,571             | )          | (1,571            | )          |
| Change in  accumulated derivative comprehensive income      |       | —         |       | —           |       | —     |       | —       |       | —           |       | —         |       | —       |       | (4,454             | )          | (4,454            | )          |
| Total  comprehensive income, net of tax                     |       | —         |       | —           |       | —     |       | —       |       | —           |       | —         |       | —       |       | —             |       | 50,448            |       |
| Stock options  exercised                                    |       | 171,060        |       | —           |       | 17         |       | —       |       | —           |       | 2,718          |       | —       |       | —             |       | 2,735             |       |
| Compensation  expense from common stock options             |       | —         |       | —           |       | —     |       | —       |       | —           |       | 463            |       | —       |       | —             |       | 463               |       |
| Unearned  compensation on restricted stock                  |       | 362,260        |       | —           |       | 36         |       | —       |       | (10,741          | )          | 11,168         |       | —       |       | —             |       | 463               |       |
| Tax benefit  related to stock options exercised             |       | —         |       | —           |       | —     |       | —       |       | —           |       | 907            |       | —       |       | —             |       | 907               |       |
| Dividends  declared on common stock                         |       | —         |       | —           |       | —     |       | —       |       | —           |       | —         |       | (7,424       | )          | —             |       | (7,424            | )          |
|                                                        |       |           |       |             |       |       |       |         |       |             |       |           |       |         |       |               |       |              |       |
| Balance at  June 30, 2005 (restated)                   |       | 74,612,053     |       | 50,032           |       | $          | 7,483      |         | $          | (788             | )          | $              | (10,741    | )            | $          | 407,693            |       | $                 | 331,339    |   | $ | (2,625 | ) | $ | 732,361 |   |

 

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

 

7

----

 

WESTERN GAS RESOURCES, INC.

NOTES TO CONSOLIDATEDFINANCIAL STATEMENTS

(Unaudited)

 

***GENERAL***

 

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

 

Theinterim consolidated financial statements presented herein should be read inconjunction with the Consolidated Financial Statements and Notes theretoincluded in our Annual Report on Form 10-K/A for the year ended December 31,2004.  The interim Consolidated FinancialStatements as of June 30, 2005 and for the three and six-month periodsended June 30, 2005 and 2004 included herein are unaudited but reflect, inthe opinion of management, all adjustments (which include only normal recurringadjustments) necessary to fairly state the results for such periods.  The results of operations for the three andsix-months ended June 30, 2005 are not necessarily indicative of theresults of operations expected for the year ended December 31, 2005.

 

In June 2005,we revised our classification in the Statement of Cash Flows for the six monthsended June 30, 2004, of the Change in the balance of outstanding checksfrom a component of Net cash provided by operating activities to a component ofCash flows from financing activities. This change in classification had the effect of decreasing previouslyreported cash provided by operating activities by $26.2 million for the sixmonths ended June 30, 2004, with a corresponding decrease in cash flowsused in financing activities.

 

***RESTATEMENTOF CONSOLIDATED FINANCIAL STATEMENTS***

 

Upon adoption of FASBStatement No. 133, “Accounting for Derivative Instruments and HedgingActivities” (“FAS 133”)in 2001, we analyzed our gas storage and gas transportation contracts indetail, and determined that these contracts had the characteristics of aderivative as described in FAS 133.  Thetreatment of these contracts as derivatives has been consistently applied sinceadoption of FAS 133 as reflected in our consolidated financial statements.  Historically, we recorded these contracts atfair value with the changes in fair value reflected in earnings. On November 8,2005, after the release of our third quarter 2005 results and prior to thefiling of the Form 10-Q for the quarter ended September 30, 2005, itcame to our attention that these contracts may not meet the definition of aderivative.  On November 21, 2005, we announced that our managementand our audit committee had completed a review of the accounting treatment ofour gas storage and gas transportation contracts and determined that thesecontracts do not meet the definition of a derivative under generally acceptedaccounting principles. Specifically, after a detailed review of the contractsand the market for those contracts, we determined that these contracts do notmeet the definition of a derivative as: (i) the market for these types ofcontracts is not sufficiently liquid for us to receive fair value in a readymarket and (ii) if any contract is assigned, there is no assurance that wewill be relieved of our rights and obligations under that contract.  Accordingly, we have restated our auditedfinancial statements for the years from 2001 through 2004 included herein andthe beginning retained earnings as of January 1, 2002.

 

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

 

The following table summarizes the impact of theaccounting adjustments necessary to correct the treatment of storage andtransportation contracts on our previously reported Net Income in our originalQuarterly Report on Form 10-Q for the period ended June 30, 2005 asfiled on August 9, 2005 (000s):

 
| ** **                                      | ** ** | **Three months ending** | ** ** | **Six months ending**  | ** ** |
|-------------------------------------------------|------------|-------------------------|------------|------------------------|------------|
| ** **                                      | ** ** | **June 30, 2005**  | ** ** | **June 30, 2004** | ** ** | **June 30, 2005** | ** ** | **June 30, 2004** | ** ** |
| Net income as previously reported               |       | $                       | 33,318     |                   | $          | 13,976 |   | $ | 65,946 |   | $ | 43,063 |   |
| Accounting correction for derivatives (pre-tax) |       | 6,830                   |       | (465                   | )          | (13,377 | ) | 7,998 |   |
| Tax impact of  above                            |       | (2,519                  | )          | 138                    |       | 4,766 |   | (2,978 | ) |
| Net income as restated                          |       | $                       | 37,629     |                   | $          | 13,649 |   | $ | 57,335 |   | $ | 48,083 |   |

 

8

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Thefollowing is a summary of the impact of these accounting adjustments on ourConsolidated Balance Sheet and Consolidated Statement of Operations as previouslyreported in the original Quarterly Report on Form 10-Q as filed on August 9,2005.  The aforementioned restatementadjustments do not affect cash flows provided by operating activities, net cashused in investing activities and net cash provided by (used in) financingactivities, although certain components of cash flows provided by operatingactivities have been restated.

 

Consolidated Balance Sheet

 
| ** **                                                   | ** ** | **For the period ending** | ** ** |
|--------------------------------------------------------------|------------|---------------------------|------------|
| ** **                                                   | ** ** | **June 30, 2005**    | ** ** | **December 31, 2004** | ** ** |
| ** **                                                   | ** ** | **As**                    | ** ** | **As** | ** ** | **As** | ** ** | **As** | ** ** |
| **(000s)**                                                   | ** ** | **Reported**              | ** ** | **Restated** | ** ** | **Reported** | ** ** | **Restated** | ** ** |
| Assets:                                                      |       |                      |       |   |   |   |   |   |   |
| Current assets  from price risk management activities        |       | 17,131                    |       | 5,970 |   | 22,238 |   | 19,893 |   |
| Deferred income  tax                                         |       | —                    |       | 3,399 |   | — |   | — |   |
| Long-term assets  from price risk management activities      |       | 539                       |       | 540 |   | 618 |   | 249 |   |
| Total Assets                                                 |       | $                         | 1,918,055  |   | $ | 1,910,294 |   | $ | 1,840,112 |   | $ | 1,837,398 |   |
|                                                         |       |                      |       |   |   |   |   |   |   |
| Liabilities and  Stockholders’ equity                   |       |                      |       |   |   |   |   |   |   |
| Current  liabilities from price risk management activities   |       | 17,474                    |       | 15,391 |   | 11,099 |   | 4,321 |   |
| Deferred income  tax                                         |       | —                    |       | — |   | — |   | 5,618 |   |
| Long-term  liabilities from price risk management activities |       | 1,437                     |       | 1,436 |   | 417 |   | 180 |   |
| Deferred income  taxes payable, net                          |       | 265,755                   |       | 265,947 |   | 247,893 |   | 243,835 |   |
| Total  liabilities                                           |       | 1,179,825                 |       | 1,177,933 |   | 1,158,084 |   | 1,152,629 |   |
|                                                         |       |                      |       |   |   |   |   |   |   |
| Stockholders’  equity                                   |       |                      |       |   |   |   |   |   |   |
| Retained  earnings                                           |       | 337,208                   |       | 331,339 |   | 278,687 |   | 281,428 |   |
| Total  stockholders’ equity                             |       | 738,230                   |       | 732,361 |   | 682,028 |   | 684,769 |   |
| Total  liabilities and stockholders’ equity             |       | $                         | 1,918,055  |   | $ | 1,910,294 |   | $ | 1,840,112 |   | $ | 1,837,398 |   |

 

Consolidated Statement ofOperations

 
| ** **                                                                                      | ** ** | **Three  Months Ending,** | ** ** | **Six  Months Ending,** | ** ** |
|-------------------------------------------------------------------------------------------------|------------|---------------------------|------------|-------------------------|------------|
| ** **                                                                                      | ** ** | **June 30,  2005**   | ** ** | **June 30,  2004** | ** ** | **June 30,  2005** | ** ** | **June 30,  2004** | ** ** |
| ** **                                                                                      | ** ** | **As**                    | ** ** | **As**                  | ** ** | **As** | ** ** | **As** | ** ** | **As** | ** ** | **As** | ** ** | **As** | ** ** | **As** | ** ** |
| **(000s)**                                                                                      | ** ** | **Reported**              | ** ** | **Restated**            | ** ** | **Reported** | ** ** | **Restated** | ** ** | **Reported** | ** ** | **Restated** | ** ** | **Reported** | ** ** | **Restated** | ** ** |
|   Revenues:                                                                                |       |                      |       |                    |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Price risk  management activities                                                               |       | 4,375                     |       | 11,205                  |       | 3,460 |   | 2,995 |   | 4,335 |   | (9,043 | ) | (2,020 | ) | 5,979 |   |
| Total revenues                                                                                  |       | $                         | 861,196    |                    | $          | 868,026 |   | $ | 726,303 |   | $ | 725,838 |   | $ | 1,715,511 |   | $ | 1,702,133 |   | $ | 1,497,519 |   | $ | 1,505,518 |   |
|                                                                                            |       |                      |       |                    |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Income before  income taxes                                                                     |       | 52,668                    |       | 59,498                  |       | 26,591 |   | 26,126 |   | 104,010 |   | 90,632 |   | 64,973 |   | 72,972 |   |
| Provision for  income taxes:                                                                    |       |                      |       |                    |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Deferred                                                                                        |       | 13,178                    |       | 15,697                  |       | 13,624 |   | 13,485 |   | 24,542 |   | 19,775 |   | 24,089 |   | 27,068 |   |
| Total provision  for income taxes                                                               |       | 19,350                    |       | 21,869                  |       | 12,616 |   | 12,477 |   | 38,064 |   | 33,297 |   | 26,624 |   | 29,603 |   |
| Income before  cumulative effect of change in accounting principle                              |       | 33,318                    |       | 37,629                  |       | 13,975 |   | 13,649 |   | 65,946 |   | 57,335 |   | 38,349 |   | 43,369 |   |
| Net income                                                                                      |       | 33,318                    |       | 37,629                  |       | 13,975 |   | 13,649 |   | 65,946 |   | 57,335 |   | 43,063 |   | 48,083 |   |
| Income  attributable to common stock                                                            |       | 33,318                    |       | 37,629                  |       | 13,956 |   | 13,630 |   | 65,946 |   | 57,335 |   | 42,228 |   | 47,248 |   |
| Earnings per  share of common stock before cumulative effect of change in accounting  principle |       | 0.45                      |       | 0.51                    |       | 0.19 |   | 0.19 |   | 0.89 |   | 0.77 |   | 0.53 |   | 0.60 |   |
| Earnings per  share of common stock                                                             |       | 0.45                      |       | 0.51                    |       | 0.19 |   | 0.19 |   | 0.89 |   | 0.77 |   | 0.60 |   | 0.67 |   |
| Income  attributable to common stock - assuming dilution                                        |       | 33,318                    |       | 37,629                  |       | 13,975 |   | 13,649 |   | 65,946 |   | 57,335 |   | 42,228 |   | 47,248 |   |
| Earnings per  share of common stock - assuming dilution                                         |       | $                         | 0.44       |                    | $          | 0.50 |   | $ | 0.19 |   | $ | 0.18 |   | $ | 0.87 |   | $ | 0.76 |   | $ | 0.58 |   | $ | 0.65 |   |

 

9

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Thenet impact of this restatement was to adjust Net income by $4.3 million and($326,000) for the three months ended June 30, 2005 and 2004,respectively, and ($8.6) million and $5.0 million for each of the six months endedJune 30, 2005 and 2004, respectively. The net impact of this restatement was to adjust Earnings per share ofcommon stock – assuming dilution by $0.06 and ($0.01) for the three monthsended June 30, 2005 and 2004, respectively, and ($0.11) and $0.7 for eachof the six months ended June 30, 2005 and 2004, respectively.

 

##### ***EQUITYTRANSACTIONS***

##### *** ***

***Conversion of Preferred Stock.*** In December 2003, we issued a notice ofredemption for a total of 800,000 shares of our $2.625 cumulative convertiblepreferred stock.  The holders of theseshares had the right to convert them into shares of our common stock in lieu ofreceiving the redemption price in cash. In January 2004, we issued an additional 1,979,244 shares of commonstock to holders who elected to convert their shares and paid $672,000 in cashproceeds to complete this redemption.  InMarch 2004, we issued an additional notice of redemption for the remaining1,260,000 shares of our $2.625 cumulative convertible preferred stock.  In April 2004, we issued an additional3,113,582 shares of common stock to holders who elected to convert their sharesand paid $391,000 in cash proceeds to complete this redemption.  After these redemptions, the $2.625cumulative convertible preferred stock was delisted from trading on the NewYork Stock Exchange and was deregistered by the SEC.

 

In the second quarter of 2005, we grantedapproximately 362,000 shares of restricted common stock to our employees.  In conjunction with the grant of restrictedstock, we will record as compensation expense over the three-year vestingperiod, the value of the restricted stock on the date of grant.  Accordingly, we recorded unearnedcompensation of $10.7 million in Stockholders’ equity and compensation expenseof $463,000 in the second quarter of 2005.

 

***EARNINGSPER SHARE OF COMMON STOCK***

 

Earnings per share of common stock are computedby dividing income attributable to common stock by the weighted average sharesof common stock outstanding.  Inaddition, earnings per share of common stock - assuming dilution is computed bydividing income attributable to common stock by the weighted average shares ofcommon stock outstanding as adjusted for potential common shares.  Income attributable to common stock is netincome less preferred stock dividends.  The following table presents the dividendsdeclared by us for each class of our outstanding equity securities (dollars inthousands, except per share amounts):

 
| ** **                    | ** ** | **Quarter Ended June 30,** | ** ** | **Six Months Ended June 30,** | ** ** |
|-------------------------------|------------|---------------------------------|------------|------------------------------------|------------|
| ** **                    | ** ** | **2005**                        | ** ** | **2004**                           | ** ** | **2005** | ** ** | **2004** | ** ** |
| Common Stock                  |       | $                               | 3,732      |                               | $          | 3,684 |   | $ | 7,425 |   | $ | 5,449 |   |
| Preferred Stock               |       | —                          |       | 19                                 |       | — |   | 835 |   |
| Total Dividends Declared      |       | $                               | 3,732      |                               | $          | 3,703 |   | $ | 7,425 |   | $ | 6,284 |   |
|                          |       |                            |       |                               |       |   |   |   |   |
| Dividends Declared Per Share: |       |                            |       |                               |       |   |   |   |   |
| Common Stock                  |       | $                               | 0.05       |                               | $          | 0.05 |   | $ | 0.10 |   | $ | 0.08 |   |
| Preferred Stock               |       | —                          |       | $                                  | 0.66       |   | — |   | $ | 1.31 |   |

 

Common stock options, unvested restricted stockgranted and, until the final conversion or redemption in April 2004, our$2.625 cumulative convertible preferred stock are potential common shares.  The following isa reconciliation of the 

 

10

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weightedaverage shares of common stock outstanding to the weighted average commonshares outstanding – assuming dilution.

 
| ** **                                                               | ** ** | **Quarter Ended June 30,** | ** ** | **Six Months Ended June 30,** | ** ** |
|--------------------------------------------------------------------------|------------|---------------------------------|------------|------------------------------------|------------|
| ** **                                                               | ** ** | **2005**                        | ** ** | **2004**                           | ** ** | **2005** | ** ** | **2004** | ** ** |
| Weighted average  shares of common stock outstanding                     |       | 74,234,424                      |       | 73,158,240                         |       | 74,191,346 |   | 70,942,578 |   |
| Potential common  shares from:                                           |       |                            |       |                               |       |   |   |   |   |
| Common stock  options and restricted stock                               |       | 1,443,965                       |       | 1,921,653                          |       | 1,411,964 |   | 1,877,462 |   |
| $2.625  Cumulative Convertible Preferred Stock                           |       | —                          |       | 249,250                            |       | — |   | — |   |
| Weighted average  shares of common stock outstanding - assuming dilution |       | 75,678,389                      |       | 75,329,143                         |       | 75,603,310 |   | 72,820,040 |   |

 

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

 

***ACCUMULATED OTHER COMPREHENSIVE INCOME***

 

Included in Accumulated other comprehensive income at June 30,2005 were unrealized losses of $4.0 million from the fair value of derivativesdesignated as cash flow hedges and unrealized gains of $2.5 million ofcumulative foreign currency translation adjustments.

 

Included in Accumulated other comprehensive income at June 30,2004 were unrealized losses of $3.5 million from the fair value of derivativesdesignated as cash flow hedges and unrealized gains of $1.7 million ofcumulative foreign currency translation adjustments.

 

##### ***REVENUERECOGNITION***

##### *** ***

 In the Gas Gathering, Processing and Treatingsegment, we recognize revenue for our services at the time the service isperformed. We record revenue from our gas and NGL marketing activities,including sales of our equity production, upon transfer of title.  In accordance with Emerging Issues TaskForce, or EITF, 03-11 “Reporting Realized Gains and Losses on DerivativeInstruments That are Subject to FASB Statement No. 133, Accounting forDerivative Instruments and Hedging Activities, and Not Held for TradingPurposes as Defined in Issue No. 02-3”, we record revenue on our physical gas and NGL marketing activitieson a gross basis versus sales net of purchases basis because we obtain title toall the gas and NGLs that we buy including third-party purchases, bear the riskof loss 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 June 30, 2005 and 2004 areimmaterial.  For our marketing activities,we utilize mark-to-market accounting for our derivatives.  In our Transportation segment, we realizerevenue on a monthly basis from firm capacity contracts under which the shipperpays for transport capacity whether or not the capacity is used and frominterruptible contracts where a fee is charged based upon volumes deliveredfrom the pipeline.

 

***OTHER MATTERS***

 

##### ***Depreciation, Depletion and Amortization of Oil andGas Properties. ***We follow the successful efforts method ofaccounting for oil and gas exploration and production activities.  Effective January 1, 2004, we redefinedthe asset groupings for the calculation of depreciation and depletion on ouroil and gas properties from a well-by-well basis to a field wide basis for eachof the Jonah, Pinedale and Sand Wash fields and to a grouping of all wellsdrilled into related coal seams for the Powder River Basin.  The cumulative effect of the change indepreciation and depletion methodology for the six months ended June 30,2004 was a benefit of $4.7 million, net of tax, or $0.07 per share of commonstock - assuming dilution, and is presented in the Consolidated Statement ofOperations under the caption Cumulative effect of change in accountingprinciple, net of tax.

##### *** ***

***Price Reporting to Gas Trade Publications. *** In 2003, we learned that several employees inour marketing department furnished inaccurate information regarding natural gastransactions to energy publications, which compile and report energy indexprices.  In July 2004, we reached asettlement of this matter with the Commodities Futures Trading Commission, orCFTC.  In conjunction with thissettlement, we paid a civil penalty of $7.0 million, and as a result ourearnings per common share in the second quarter and six months ended June 30,2004 were reduced by $0.09 and $0.10, respectively.  In the second quarter of 2005, we reached asettlement of a related claim with a private litigant for $3.8 millionafter-tax, or $0.05 per common share for both the three and six months ended June 30,2005.  For additional information, seeLegal Proceedings in these Notes to Consolidated Financial Statements.

 

11

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***INCOME TAXES***

 

TheTotal provision for income taxes, as a percentage of Income before taxes was approximately36.8% and 36.7%, respectively, during the quarter and six months ended June 30,2005 as compared to 47.8% and 40.6%, respectively, in the same periods of2004.  This decrease is due to the civilpenalty paid to the CFTC in 2004, which was non-deductible for tax purposes.

 

***DERIVATIVE INSTRUMENTS AND HEDGINGACTIVITIES***

 

A netloss was recognized in earnings through Sale of residue gas and Sale of naturalgas liquids during the three and six months ended June 30, 2005 fromhedging activities of $657,000 and $170,000, respectively.  Also during these periods we recognized aloss from hedge ineffectiveness of $37,000 and $125,000, respectively, throughPrice risk management activities.

 

Thegains and losses currently reflected in Accumulated other comprehensive incomewill be reclassified to earnings as the hedged gas or NGLs is sold.  Based on the prices for our products on June 30,2005, approximately $4.0 million of losses in Accumulated other comprehensiveincome will be reclassified to earnings, of which $2.5 million will bereclassified in the remainder of 2005.

 

***SUPPLEMENTARY CASH FLOW INFORMATION***

*** ***

Interest paid was $11.7 million and $13.3million for the six months ended June 30, 2005 and 2004, respectively. A total of $11.0 million and $7.7 million waspaid in income taxes in the six months ended June 30, 2005 and 2004,respectively.  Asset retirementobligations of $7.7 million were recorded for capitalized assets for the sixmonths ended June 30, 2005.  Theasset retirement and associated obligations are non-cash transactions forpresentation on the Consolidated Statement of Cash Flows.

 

***STOCK COMPENSATION***

 

As permitted under SFAS No. 123, “Accountingfor Stock-Based Compensation”, we have elected to continue to measurecompensation costs for stock-based employee compensation plans as prescribed byAccounting Principles Board Opinion No. 25, “Accounting for Stock Issuedto Employees.”  We have complied with thepro forma disclosure requirements of SFAS No. 123 as required under thepronouncement.  We realize an income taxbenefit from the exercise of non-qualified stock options related to the amountby which the market price at the date of exercise exceeds the optionprice.  This tax benefit is credited toAdditional paid-in capital.

 

In the second quarterof 2005, we granted approximately 747,000 options to purchase our common stockat the market price based on the average closing price for the ten days priorto grant and approximately 362,000 shares of restricted common stock to ouremployees.  In conjunction with the grantof restricted stock, we will record as compensation expense over the three-yearvesting period, the value of the restricted stock on the date of grant.  Accordingly, we recorded unearnedcompensation expense of $463,000 in the second quarter of 2005.

 

SFAS No. 123 requires pro forma disclosuresfor each quarter that a Statement of Operations is presented.  The following isa summary of the options to purchase our common stock granted during thequarters and six months ended June 30, 2005 and 2004, respectively.

 
| ** **                | ** ** | **Quarter Ended June 30,** | ** ** | **Six Months Ended June 30,** | ** ** |
|---------------------------|------------|---------------------------------|------------|------------------------------------|------------|
| ** **                | ** ** | **2005**                        | ** ** | **2004**                           | ** ** | **2005** | ** ** | **2004** | ** ** |
| 2002 Plan                 |       | 54,000                          |       | 40,000                             |       | 137,000 |   | 75,000 |   |
| 2002 Directors’ Plan |       | 32,000                          |       | 32,000                             |       | 32,000 |   | 32,000 |   |
| 2005 Plan                 |       | 747,000                         |       | —                             |       | 747,000 |   | — |   |
| Total options granted     |       | 833,000                         |       | 72,000                             |       | 916,000 |   | 107,000 |   |

 

The following is a summary of the weightedaverage fair value per share of the options granted during thequarters and six months ended June 30, 2005 and 2004, respectively.

 

12

----

 
| ** **                | ** ** | **Quarter Ended June 30,** | ** ** | **Six Months Ended June 30,** | ** ** |
|---------------------------|------------|---------------------------------|------------|------------------------------------|------------|
| ** **                | ** ** | **2005**                        | ** ** | **2004**                           | ** ** | **2005** | ** ** | **2004** | ** ** |
| 2002 Plan                 |       | $                               | 14.04      |                               | $          | 14.89 |   | $ | 15.01 |   | $ | 13.20 |   |
| 2002 Directors’ Plan |       | $                               | 14.79      |                               | $          | 12.13 |   | $ | 14.79 |   | $ | 12.13 |   |
| 2005 Plan                 |       | $                               | 13.25      |                               | —     |   | $ | 13.25 |   | — |   |

 

These values for the options granted during thequarter and six months ended June 30, 2005 wereestimated using the Black-Scholes option-pricing model with the followingassumptions:

 
| ** **                     | ** ** | **Quarter Ended June 30, 2005** | ** ** | **Six Months Ended June 30, 2005** | ** ** |
|--------------------------------|------------|--------------------------------------|------------|-----------------------------------------|------------|
| ** **                     | ** ** | **2002 Plan**                        | ** ** | **2002  Directors’  Plan**         | ** ** | **2005 Plan** | ** ** | **2002 Plan** | ** ** | **2002  Directors’  Plan** | ** ** | **2005 Plan** | ** ** |
| Risk-free interest rate        |       | 4.30                                 | %          | 4.38                                    | %          | 4.27 | % | 4.35 | % | 4.38 | % | 4.27 | % |
| Expected life (in years)       |       | 7                                    |       | 7                                       |       | 7 |   | 7 |   | 7 |   | 7 |   |
| Expected volatility            |       | 37                                   | %          | 37                                      | %          | 37 | % | 37 | % | 37 | % | 37 | % |
| Expected dividends (quarterly) |       | $                                    | 0.05       |                                    | $          | 0.05 |   | $ | 0.05 |   | $ | 0.05 |   | $ | 0.05 |   | $ | 0.05 |   |
|                                |            |                                      |            |                                         |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

Under SFAS No. 123, the fair market valueof the options at the grant date is amortized over the appropriate vestingperiod for purposes of calculating compensation expense.  If we had recorded compensation expense forour grants under our stock-based compensation plans consistent with the fairvalue method under this pronouncement, our net income, income attributable tocommon stock, earnings per share of common stock and earnings per share ofcommon stock - assuming dilution would approximate the pro forma amounts below(dollars in thousands, except per share amounts):

 
| ** **                                                                                                                                     | ** ** | **Quarter Ended June 30,** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------|------------|
| ** **                                                                                                                                     | ** ** | **2005**                        | ** ** | **2005** | ** ** | **2004** | ** ** | **2004** | ** ** |
| ** **                                                                                                                                     | ** ** | **As Reported  Restated**       | ** ** | **Pro Forma  Restated** | ** ** | **As Reported  Restated** | ** ** | **Pro Forma  Restated** | ** ** |
| Net income                                                                                                                                     |       | $                               | 37,629     |   | $ | 35,062 |   | $ | 13,649 |   | $ | 12,523 |   |
| Net income  attributable to common stock                                                                                                       |       | 37,629                          |       | 35,062 |   | 13,630 |   | 12,504 |   |
| Earnings per  share of common stock                                                                                                            |       | 0.51                            |       | 0.47 |   | 0.19 |   | 0.17 |   |
| Earnings per  share of common stock - assuming dilution                                                                                        |       | 0.50                            |       | 0.46 |   | 0.18 |   | 0.17 |   |
| Stock-based  employee compensation cost, net of related tax effects, included in net  income                                                   |       | 412                             |       | — |   | 188 |   | — |   |
| Stock-based  employee compensation cost, net of related tax effects, includable in net  income if the fair value based method had been applied |       | $                               | —     |   | $ | 2,979 |   | $ | — |   | $ | 1,314 |   |

 
| ** **                                                                                                                                     | ** ** | **Six Months Ended June 30,** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------------|------------|
| ** **                                                                                                                                     | ** ** | **2005**                           | ** ** | **2005** | ** ** | **2004** | ** ** | **2004** | ** ** |
| ** **                                                                                                                                     | ** ** | **As Reported  Restated**          | ** ** | **Pro Forma  Restated** | ** ** | **As Reported  Restated** | ** ** | **Pro Forma  Restated** | ** ** |
| Net income                                                                                                                                     |       | $                                  | 57,335     |   | $ | 53,089 |   | $ | 48,083 |   | $ | 45,816 |   |
| Net income  attributable to common stock                                                                                                       |       | 57,335                             |       | 53,089 |   | 47,248 |   | 44,981 |   |
| Earnings per  share of common stock                                                                                                            |       | 0.77                               |       | 0.71 |   | 0.67 |   | 0.63 |   |
| Earnings per  share of common stock -assuming dilution                                                                                         |       | 0.76                               |       | 0.70 |   | 0.65 |   | 0.63 |   |
| Stock-based  employee compensation cost, net of related tax effects, included in net  income                                                   |       | 585                                |       | — |   | 300 |   | — |   |
| Stock-based  employee compensation cost, net of related tax effects, includable in net  income if the fair value based method had been applied |       | $                                  | —     |   | $ | 4,831 |   | $ | — |   | $ | 2,567 |   |

 

13

----

 

***SEGMENT REPORTING***

*** ***

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

 

***Gas Gathering, Processing and Treating.***  In this segment, collectively with theMarketing and Transportation segments referred to as the midstream operations,we connect producers’ wells (including those of our Exploration and Productionsegment) to our gathering systems for delivery to our processing or treatingplants, process the natural gas to extract NGLs and treat the natural gas inorder to meet pipeline specifications. In some areas, where no processing is required, we gather and compressproducers’ gas and deliver it to pipelines for further delivery to market.  Except for volumes taken in kind by ourproducers, the Marketing segment sells the residue gas and NGLs extracted atmost of our facilities.

 

Substantiallyall gas flowing through our gathering, processing and treating facilities issupplied under three types of contracts providing for the purchase, treating orprocessing of natural gas for periods ranging from one month to twenty years orin some cases for the life of the oil and gas lease.  Approximately 68% of our plant facilities’gross margin, or revenues at the plant less product purchases, for the month ofJune 2005 was pursuant to percentage-of-proceeds agreements in which weare typically responsible for the marketing of the gas and NGLs.  Under these agreements, we pay producers aspecified percentage of the net proceeds received from the sale of the gas and theNGLs.

 

Approximately21% of our plant facilities’ gross margin for the month of June 2005 waspursuant to contracts that are primarily fee-based from which we receive a setfee for each Mcf of gas gathered and/or processed. This type of contract providesus with a steady revenue stream that is not dependent on commodity prices,except to the extent that low prices may cause a producer to delay drilling.

 

Approximately11% of our plant facilities’ gross margin for the month of June 2005 waspursuant to contracts with “keepwhole” arrangements or wellhead purchasecontracts.  Under these 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 ofresidue gas equal on a Btu basis to the natural gas received at the plantinlet.  The “keepwhole” component of thecontracts permits us to benefit when the value of the NGLs is greater as aliquid than as a portion of the residue gas stream.  However, we are adversely affected when thevalue of the NGLs is lower as a liquid than as a portion of the residue gasstream.

 

***Explorationand Production.*** The activities of the Exploration and Production segment include theexploration and development of gas properties primarily in the Rocky Mountainarea and other unconventional gas plays, including those where our gatheringand/or processing facilities are located. The Marketing segment sells the majority of the production from theseproperties and remits to the Exploration and Production segment all of theproceeds from the sales of its gas net of transportation charges.

 

***Marketing.***  Our Marketing segment buys and sells gas andNGLs in the United States and Canada from and to a variety of customers.  Revenues in this segment are sensitive tochanges in the market prices of the underlying commodities.  The marketing of products purchased fromthird parties typically results in low sales margins relative to the salesprice.  We sell our products underagreements with varying terms and conditions in order to match seasonal andother changes in demand.  Also includedin this segment are our Canadian marketing operations, which are conductedthrough our wholly owned subsidiary WGR Canada, Inc. and are immaterialfor separate presentation.

 

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

 

***SegmentInformation.*** The following tables set forth oursegment information as of and for the quarter and six months ended June 30,2005 and 2004 (dollars in thousands). Due to our integrated operations, the use of allocations in thedetermination of business segment information is necessary.  Inter-segment revenues are valued at pricescomparable to those of unaffiliated customers. In the interim segment information, prior period Corporate Plantoperating and transportation expense of $(484,000) and $451,000 for the quarterand six months ended June 30, 2004, respectively, has been reclassified tothe Gas Gathering and Processing segment to conform to the presentation used in2005.

 

14

----

 

**Quarterended June 30, 2005**

**Restated**

 
| ** **                                        | ** ** | **Gas  Gathering  and Processing** | ** ** | **Exploration    and Production** | ** ** | **Marketing** | ** ** | **Transportation** | ** ** | **Other** | ** ** | **Eliminating  Entries** | ** ** | **Total** | ** ** |
|---------------------------------------------------|------------|------------------------------------|------------|----------------------------------------|------------|---------------|------------|--------------------|------------|-----------|------------|--------------------------|------------|-----------|------------|
| Revenues from unaffiliated  customers:       |       |                               |       |                                   |       |          |       |               |       |      |       |                     |       |      |       |
| Sale of gas                                       |       | $                                  | 956        |                                   | $          | 3,040         |       | $                  | 673,235    |      | $          | 409                      |       | $         | —     |   | $ | — |   | $ | 677,640 |   |
| Sale of natural  gas liquids                      |       | 3                                  |       | —                                 |       | 150,581       |       | —             |       | —    |       | —                   |       | 150,584   |       |
| Equity hedges:                                    |       |                               |       |                                   |       |          |       |               |       |      |       |                     |       |      |       |
| Residue                                           |       | 68                                 |       | 378                                    |       | —        |       | —             |       | —    |       | —                   |       | 446       |       |
| Liquids                                           |       | (1,103                             | )          | —                                 |       | —        |       | —             |       | —    |       | —                   |       | (1,103    | )          |
| Gathering,  processing and transportation revenue |       | 26,154                             |       | —                                 |       | —        |       | 1,669              |       | —    |       | —                   |       | 27,823    |       |
| Total revenues from unaffiliated customers:       |       | 26,078                             |       | 3,418                                  |       | 823,816       |       | 2,078              |       | —    |       | —                   |       | 855,390   |       |
|                                              |       |                               |       |                                   |       |          |       |               |       |      |       |                     |       |      |       |
| Inter-segment sales                               |       | 300,326                            |       | 78,376                                 |       | 24,940        |       | 3,353              |       | 10        |       | (407,005                 | )          | —    |       |
| Price risk management activities                  |       | (37                                | )          | —                                 |       | 11,242        |       | —             |       | —    |       | —                   |       | 11,205    |       |
| Interest Income                                   |       | —                             |       | 4                                      |       | 18            |       | —             |       | 12,435    |       | (12,457                  | )          | —    |       |
| Other, net                                        |       | 1,089                              |       | 118                                    |       | 3             |       | —             |       | 221       |       | —                   |       | 1,431     |       |
| Total revenues                                    |       | 327,456                            |       | 81,916                                 |       | 860,019       |       | 5,431              |       | 12,666    |       | (419,462                 | )          | 868,026   |       |
|                                              |       |                               |       |                                   |       |          |       |               |       |      |       |                     |       |      |       |
| Product purchases                                 |       | 252,906                            |       | 1,084                                  |       | 849,636       |       | 776                |       | —    |       | (396,886                 | )          | 707,516   |       |
| Plant and transportation operating expense        |       | 25,852                             |       | 164                                    |       | 144           |       | 1,653              |       | —    |       | (982                     | )          | 26,831    |       |
| Oil and gas exploration and production expense    |       | —                             |       | 33,155                                 |       | —        |       | —             |       | —    |       | (9,096                   | )          | 24,059    |       |
| (Earnings) from equity investments                |       | (2,246                             | )          | —                                 |       | —        |       | —             |       | —    |       | —                   |       | (2,246    | )          |
| Segment operating profit                          |       | 50,944                             |       | 47,513                                 |       | 10,239        |       | 3,002              |       | 12,666    |       | (12,498                  | )          | 111,866   |       |
|                                              |       |                               |       |                                   |       |          |       |               |       |      |       |                     |       |      |       |
| Depreciation, depletion and  amortization    |       | 11,594                             |       | 16,899                                 |       | 35            |       | 436                |       | 1,835     |       | —                   |       | 30,799    |       |
| Selling and administrative expense                |       | —                             |       | —                                 |       | —        |       | —             |       | 17,546    |       | (9                       | )          | 17,537    |       |
| (Gain) loss from sale of assets                   |       | (213                               | )          | 61                                     |       | —        |       | 151                |       | —    |       | —                   |       | (1        | )          |
| Interest expense                                  |       | —                             |       | 3                                      |       | 587           |       | (194               | )          | 16,094    |       | (12,457                  | )          | 4,033     |       |
| Income before tax                                 |       | $                                  | 39,563     |                                   | $          | 30,550        |       | $                  | 9,617      |      | $          | 2,609                    |       | $         | (22,809    | ) | $ | (32 | ) | $ | 59,498 |   |
|                                              |       |                               |       |                                   |       |          |       |               |       |      |       |                     |       |      |       |
| Identifiable assets:                              |       |                               |       |                                   |       |          |       |               |       |      |       |                     |       |      |       |
| Equity  investments                               |       | $                                  | 32,675     |                                   | $          | —        |       | $                  | —     |      | $          | 1,150                    |       | $         | 857,160    |   | $ | (854,901 | ) | $ | 36,084 |   |
| Property and  equipment                           |       | 725,336                            |       | 539,888                                |       | 13            |       | 39,154             |       | 60,438    |       | (568                     | )          | 1,364,261 |       |
| Other allocated  assets                           |       | 38,465                             |       | 13,960                                 |       | 150,709       |       | 35,804             |       | 339,206   |       | (68,195                  | )          | 509,949   |       |
| Total identifiable assets                         |       | $                                  | 796,476    |                                   | $          | 553,848       |       | $                  | 150,722    |      | $          | 76,108                   |       | $         | 1,256,804  |   | $ | (923,664 | ) | $ | 1,910,294 |   |

 

15

----

 

**Quarter ended June 30, 2004**

**Restated**

 
| ** **                                        | ** ** | **Gas  Gathering and Processing** | ** ** | **Exploration  and  Production** | ** ** | **Marketing** | ** ** | **Transportation** | ** ** | **Other** | ** ** | **Eliminating Entries** | ** ** | **Total** | ** ** |
|---------------------------------------------------|------------|----------------------------------------|------------|----------------------------------|------------|---------------|------------|--------------------|------------|-----------|------------|------------------------------|------------|-----------|------------|
|                                              |       |                                   |       |                             |       |          |       |               |       |      |       |                         |       |      |       |
| Revenues from  unaffiliated  customers:      |       |                                   |       |                             |       |          |       |               |       |      |       |                         |       |      |       |
| Sale of gas                                       |       | $                                      | 965        |                             | $          | 1,544         |       | $                  | 591,336    |      | $          | 303                          |       | $         | —     |   | $ | — |   | $ | 594,148 |   |
| Sale of natural  gas liquids                      |       | 2                                      |       | —                           |       | 104,605       |       | —             |       | —    |       | —                       |       | 104,607   |       |
| Equity hedges:                                    |       |                                   |       |                             |       |          |       |               |       |      |       |                         |       |      |       |
| Residue                                           |       | 116                                    |       | 1,617                            |       | —        |       | —             |       | —    |       | —                       |       | 1,733     |       |
| Liquids                                           |       | (2,586                                 | )          | —                           |       | —        |       | —             |       | —    |       | —                       |       | (2,586    | )          |
| Gathering,  processing and transportation revenue |       | 22,756                                 |       | —                           |       | —        |       | 1,654              |       | —    |       | —                       |       | 24,410    |       |
| Total revenues  from unaffiliated customers:      |       | 21,253                                 |       | 3,161                            |       | 695,941       |       | 1,957              |       | —    |       | —                       |       | 722,312   |       |
|                                              |       |                                   |       |                             |       |          |       |               |       |      |       |                         |       |      |       |
| Inter-segment  sales                              |       | 251,772                                |       | 60,425                           |       | 14,796        |       | 3,711              |       | —    |       | (330,704                     | )          | —    |       |
| Price risk  management activities                 |       | (5                                     | )          | —                           |       | 3,000         |       | —             |       | —    |       | —                       |       | 2,995     |       |
| Interest Income                                   |       | —                                 |       | 3                                |       | —        |       | —             |       | 4,333     |       | (4,336                       | )          | —    |       |
| Other, net                                        |       | 471                                    |       | —                           |       | 7             |       | 47                 |       | 6         |       | —                       |       | 531       |       |
| Total revenues                                    |       | 273,491                                |       | 63,589                           |       | 713,744       |       | 5,715              |       | 4,339     |       | (335,040                     | )          | 725,838   |       |
|                                              |       |                                   |       |                             |       |          |       |               |       |      |       |                         |       |      |       |
| Product purchases                                 |       | 212,543                                |       | 304                              |       | 710,825       |       | 1,374              |       | —    |       | (322,880                     | )          | 602,166   |       |
| Plant and  transportation operating expense       |       | 21,189                                 |       | (178                             | )          | 70            |       | 1,812              |       | —    |       | (638                         | )          | 22,255    |       |
| Oil and gas  exploration and production expense   |       | —                                 |       | 26,904                           |       | —        |       | —             |       | —    |       | (7,092                       | )          | 19,812    |       |
| (Earnings) from  equity investments               |       | (1,776                                 | )          | —                           |       | —        |       | —             |       | —    |       | —                       |       | (1,776    | )          |
| Segment operating  profit                         |       | 41,535                                 |       | 36,559                           |       | 2,849         |       | 2,529              |       | 4,339     |       | (4,430                       | )          | 83,381    |       |
|                                              |       |                                   |       |                             |       |          |       |               |       |      |       |                         |       |      |       |
| Depreciation,  depletion and  amortization   |       | 9,211                                  |       | 10,875                           |       | 35            |       | 408                |       | 1,819     |       | —                       |       | 22,348    |       |
| Selling and  administrative expense               |       | —                                 |       | —                           |       | —        |       | —             |       | 17,266    |       | (11                          | )          | 17,255    |       |
| (Gain) loss from  sale of assets                  |       | 244                                    |       | (196                             | )          | —        |       | —             |       | 292       |       | 1,299                        |       | 1,639     |       |
| Loss from early  extinguishment  of debt     |       | —                                 |       | —                           |       | —        |       | —             |       | 10,662    |       |                         |       | 10,662    |       |
| Interest expense                                  |       | —                                 |       | 8                                |       | 82            |       | (71                | )          | 9,668     |       | (4,336                       | )          | 5,351     |       |
|                                              |       |                                   |       |                             |       |          |       |               |       |      |       |                         |       |      |       |
| Income before tax                                 |       | $                                      | 32,080     |                             | $          | 25,872        |       | $                  | 2,732      |      | $          | 2,192                        |       | $         | (35,368    | ) | $ | (1,382 | ) | $ | 26,126 |   |
|                                              |       |                                   |       |                             |       |          |       |               |       |      |       |                         |       |      |       |
| Identifiable  assets:                             |       |                                   |       |                             |       |          |       |               |       |      |       |                         |       |      |       |
| Equity  investments                               |       | $                                      | 2,469      |                             | $          | —        |       | $                  | —     |      | $          | —                       |       | $         | 697,196    |   | $ | (662,882 | ) | $ | 36,783 |   |
| Property and  equipment                           |       | 623,982                                |       | 321,009                          |       | 1,253         |       | 38,225             |       | 56,240    |       | (569                         | )          | 1,040,140 |       |
| Other allocated  assets                           |       | 2,739                                  |       | 7,004                            |       | 122,284       |       | 44,951             |       | 281,912   |       | (38,451                      | )          | 420,439   |       |
| Total  identifiable assets                        |       | $                                      | 629,190    |                             | $          | 328,013       |       | $                  | 123,537    |      | $          | 83,176                       |       | $         | 1,035,348  |   | $ | (701,902 | ) | $ | 1,497,362 |   |

 

16

----

 

**Six months ended June 30, 2005**

**Restated**

 
| ** **                                        | ** ** | **Gas  Gathering  and Processing** | ** ** | **Exploration  and  Production** | ** ** | **Marketing** | ** ** | **Transportation** | ** ** | **Other** | ** ** | **Eliminating  Entries** | ** ** | **Total** | ** ** |
|---------------------------------------------------|------------|------------------------------------|------------|----------------------------------|------------|---------------|------------|--------------------|------------|-----------|------------|--------------------------|------------|-----------|------------|
|                                              |       |                               |       |                             |       |          |       |               |       |      |       |                     |       |      |       |
| Revenues from unaffiliated  customers:       |       |                               |       |                             |       |          |       |               |       |      |       |                     |       |      |       |
| Sale of gas                                       |       | $                                  | 730        |                             | $          | 7,075         |       | $                  | 1,363,568  |      | $          | 1,154                    |       | $         | —     |   | $ | — |   | $ | 1,372,527 |   |
| Sale of natural  gas liquids                      |       | 51                                 |       | —                           |       | 284,347       |       | —             |       |      |       |                     |       | 284,398   |       |
| Equity hedges:                                    |       |                               |       |                             |       |          |       |               |       |      |       |                     |       |      |       |
| Residue                                           |       | 175                                |       | 1,604                            |       | —        |       | —             |       | —    |       | —                   |       | 1,779     |       |
| Liquids                                           |       | (1,949                             | )          | —                           |       | —        |       | —             |       | —    |       | —                   |       | (1,949    | )          |
| Gathering,  processing and transportation revenue |       | 48,446                             |       | (162                             | )          | —        |       | 3,419              |       | —    |       | —                   |       | 51,703    |       |
| Total revenues from unaffiliated customers:       |       | 47,453                             |       | 8,517                            |       | 1,647,915     |       | 4,573              |       | —    |       | —                   |       | 1,708,458 |       |
|                                              |       |                               |       |                             |       |          |       |               |       |      |       |                     |       |      |       |
| Inter-segment sales                               |       | 576,179                            |       | 147,643                          |       | 42,644        |       | 6,795              |       | 20        |       | (773,281                 | )          | —    |       |
| Price risk management activities                  |       | (125                               | )          | —                           |       | (8,918        | )          | —             |       | —    |       | —                   |       | (9,043    | )          |
| Interest Income                                   |       | —                             |       | 8                                |       | 18            |       | —             |       | 21,937    |       | (21,963                  | )          | —    |       |
| Other, net                                        |       | 2,194                              |       | 120                              |       | 3             |       | —             |       | 401       |       | —                   |       | 2,718     |       |
| Total revenues                                    |       | 625,701                            |       | 156,288                          |       | 1,681,662     |       | 11,368             |       | 22,358    |       | (795,244                 | )          | 1,702,133 |       |
|                                              |       |                               |       |                             |       |          |       |               |       |      |       |                     |       |      |       |
| Product purchases                                 |       | 474,358                            |       | 2,364                            |       | 1,689,680     |       | 1,634              |       | —    |       | (753,166                 | )          | 1,414,870 |       |
| Plant and transportation operating expense        |       | 52,491                             |       | 168                              |       | 146           |       | 3,464              |       | —    |       | (1,739                   | )          | 54,530    |       |
| Oil and gas exploration and production expense    |       | —                             |       | 67,294                           |       | —        |       | —             |       | —    |       | (18,339                  | )          | 48,955    |       |
| (Earnings) from equity investments                |       | (4,380                             | )          | —                           |       | —        |       | —             |       | —    |       | —                   |       | (4,380    | )          |
| Segment operating profit (loss)                   |       | 103,232                            |       | 86,462                           |       | (8,164        | )          | 6,270              |       | 22,358    |       | (22,000                  | )          | 188,158   |       |
|                                              |       |                               |       |                             |       |          |       |               |       |      |       |                     |       |      |       |
| Depreciation, depletion and  amortization    |       | 22,872                             |       | 32,528                           |       | 71            |       | 839                |       | 3,567     |       | —                   |       | 59,877    |       |
| Selling and administrative expense                |       | —                             |       | —                           |       | —        |       | —             |       | 30,089    |       | (20                      | )          | 30,069    |       |
| (Gain) loss from sale of assets                   |       | (182                               | )          | 61                               |       | —        |       | 148                |       | —    |       | —                   |       | 27        |       |
| Interest expense                                  |       | 5                                  |       | 4                                |       | 589           |       | (348               | )          | 29,266    |       | (21,963                  | )          | 7,553     |       |
|                                              |       |                               |       |                             |       |          |       |               |       |      |       |                     |       |      |       |
| Income before tax                                 |       | $                                  | 80,537     |                             | $          | 53,869        |       | $                  | (8,824     | )         | $          | 5,631                    |       | $         | (40,564    | ) | $ | (17 | ) | $ | 90,632 |   |
|                                              |       |                               |       |                             |       |          |       |               |       |      |       |                     |       |      |       |
| Identifiable assets:                              |       |                               |       |                             |       |          |       |               |       |      |       |                     |       |      |       |
| Equity  investments                               |       | $                                  | 32,675     |                             | $          | —        |       | $                  | —     |      | $          | 1,150                    |       | $         | 857,160    |   | $ | (854,901 | ) | $ | 36,084 |   |
| Property and  equipment                           |       | 725,336                            |       | 539,888                          |       | 13            |       | 39,154             |       | 60,438    |       | (568                     | )          | 1,364,261 |       |
| Other allocated  assets                           |       | 38,465                             |       | 13,960                           |       | 150,709       |       | 35,804             |       | 339,206   |       | (68,195                  | )          | 509,949   |       |
| Total identifiable assets                         |       | $                                  | 796,476    |                             | $          | 553,848       |       | $                  | 150,722    |      | $          | 76,108                   |       | $         | 1,256,804  |   | $ | (923,664 | ) | $ | 1,910,294 |   |

 

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**Six months ended June 30, 2004**

**Restated**

 
| ** **                                        | ** ** | **Gas  Gathering  and Processing** | ** ** | **Exploration  and  Production** | ** ** | **Marketing** | ** ** | **Transportation** | ** ** | **Other** | ** ** | **Eliminating  Entries** | ** ** | **Total** | ** ** |
|---------------------------------------------------|------------|------------------------------------|------------|----------------------------------|------------|---------------|------------|--------------------|------------|-----------|------------|--------------------------|------------|-----------|------------|
|                                              |       |                               |       |                             |       |          |       |               |       |      |       |                     |       |      |       |
| Revenues from  unaffiliated  customers:      |       |                               |       |                             |       |          |       |               |       |      |       |                     |       |      |       |
| Sale of gas                                       |       | $                                  | 1,889      |                             | $          | 3,783         |       | $                  | 1,251,272  |      | $          | 865                      |       | $         | —     |   | $ | — |   | $ | 1,257,809 |   |
| Sale of natural  gas liquids                      |       | 3                                  |       | —                           |       | 199,911       |       | —             |       |      |       |                     |       | 199,914   |       |
| Equity hedges:                                    |       |                               |       |                             |       |          |       |               |       |      |       |                     |       |      |       |
| Residue                                           |       | 265                                |       | 3,117                            |       | —        |       | —             |       | —    |       | —                   |       | 3,382     |       |
| Liquids                                           |       | (4,978                             | )          | —                           |       | —        |       | —             |       | —    |       | —                   |       | (4,978    | )          |
| Gathering,  processing and transportation revenue |       | 37,842                             |       | —                           |       | —        |       | 3,397              |       | —    |       | —                   |       | 41,239    |       |
| Total revenues  from unaffiliated customers:      |       | 35,021                             |       | 6,900                            |       | 1,451,183     |       | 4,262              |       | —    |       | —                   |       | 1,497,366 |       |
|                                              |       |                               |       |                             |       |          |       |               |       |      |       |                     |       |      |       |
| Inter-segment  sales                              |       | 509,424                            |       | 116,356                          |       | 27,601        |       | 7,145              |       | —    |       | (660,526                 | )          | —    |       |
| Price risk  management activities                 |       | (26                                | )          | —                           |       | 6,005         |       | —             |       | —    |       | —                   |       | 5,979     |       |
| Interest Income                                   |       | —                             |       | 3                                |       | —        |       | —             |       | 8,342     |       | (8,345                   | )          | —    |       |
| Other, net                                        |       | 812                                |       | 1                                |       | 5             |       | 47                 |       | 1,308     |       | —                   |       | 2,173     |       |
| Total revenues                                    |       | 545,231                            |       | 123,260                          |       | 1,484,794     |       | 11,454             |       | 9,650     |       | (668,871                 | )          | 1,505,518 |       |
|                                              |       |                               |       |                             |       |          |       |               |       |      |       |                     |       |      |       |
| Product purchases                                 |       | 428,120                            |       | 932                              |       | 1,470,694     |       | 2,955              |       | —    |       | (643,193                 | )          | 1,259,508 |       |
| Plant and  transportation operating expense       |       | 42,288                             |       | 70                               |       | (172          | )          | 3,572              |       | —    |       | (1,569                   | )          | 44,189    |       |
| Oil and gas  exploration and production expense   |       | —                             |       | 52,585                           |       | —        |       | —             |       | —    |       | (15,663                  | )          | 36,922    |       |
| (Earnings) from  equity investments               |       | (3,702                             | )          | —                           |       | —        |       | —             |       | —    |       | —                   |       | (3,702    | )          |
| Segment operating  profit                         |       | 78,525                             |       | 69,673                           |       | 14,272        |       | 4,927              |       | 9,650     |       | (8,446                   | )          | 168,601   |       |
|                                              |       |                               |       |                             |       |          |       |               |       |      |       |                     |       |      |       |
| Depreciation,  depletion and  amortization   |       | 18,212                             |       | 21,866                           |       | 52            |       | 824                |       | 4,020     |       | —                   |       | 44,974    |       |
| Selling and  administrative expense               |       | —                             |       | —                           |       | —        |       | —             |       | 27,227    |       | (26                      | )          | 27,201    |       |
| (Gain) loss from  sale of assets                  |       | 244                                |       | (196                             | )          | —        |       | —             |       | 292       |       | 1,299                    |       | 1,639     |       |
| Loss from early  extinguishment of debt           |       | —                             |       | —                           |       | —        |       | —             |       | 10,662    |       | —                   |       | 10,662    |       |
| Interest expense                                  |       | —                             |       | 42                               |       | 177           |       | (133               | )          | 19,412    |       | (8,345                   | )          | 11,153    |       |
| Income before tax                                 |       | $                                  | 60,069     |                             | $          | 47,961        |       | $                  | 14,043     |      | $          | 4,236                    |       | $         | (51,963    | ) | $ | (1,374 | ) | $ | 72,972 |   |
|                                              |       |                               |       |                             |       |          |       |               |       |      |       |                     |       |      |       |
| Identifiable  assets:                             |       |                               |       |                             |       |          |       |               |       |      |       |                     |       |      |       |
| Equity  investments                               |       | $                                  | 2,469      |                             | $          | —        |       | $                  | —     |      | $          | —                   |       | $         | 697,196    |   | $ | (662,882 | ) | $ | 36,783 |   |
| Property and  equipment                           |       | 623,982                            |       | 321,009                          |       | 1,253         |       | 38,225             |       | 56,240    |       | (569                     | )          | 1,040,140 |       |
| Other allocated  assets                           |       | 2,739                              |       | 7,004                            |       | 122,284       |       | 44,951             |       | 281,912   |       | (38,451                  | )          | 420,439   |       |
| Total  identifiable assets                        |       | $                                  | 629,190    |                             | $          | 328,013       |       | $                  | 123,537    |      | $          | 83,176                   |       | $         | 1,035,348  |   | $ | (701,902 | ) | $ | 1,497,362 |   |

 

***LEGAL PROCEEDINGS***

 

***Gracey et al. v. Western Gas Resources, Inc.et al., United States District Court, Southern District of New York, Case No. 03-CV-6186(vm) (S.D.N.Y.). ***OnSeptember 17, 2004, the plaintiffs, traders of natural gas futurescontracts on NYMEX, filed this action on behalf of themselves and a putativeclass of other similarly situated plaintiffs. In the complaint, the plaintiffs claim that we manipulated the prices ofnatural gas futures on the NYMEX in violation of the Commodity Exchange Act, orCEA, by reporting allegedly “inaccurate, misleading and false tradinginformation” to trade publications that compile and publish indices of naturalgas spot prices.  In addition, thecomplaint asserts that we aided and abetted the alleged CEA violations ofothers.  In June 2005, while admittingno liability, we entered into a Stipulation and Agreement of Settlement withthe plaintiffs for $5.9 million.  Thissettlement is subject to approval by the court and was accrued in the secondquarter of 2005.

 

***United States of America and ex rel. Jack J. Grynberg v. Western GasResources, Inc., et al., United States District Court, District ofColorado, Civil Action No. 97-D-1427. ***We, along with over 300 other natural gas companies, are 

 

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defendants in litigation filed on September 30, 1997, in 72separate actions filed by Mr. Grynberg on behalf of the federalgovernment.  The allegations made by Mr. Grynbergare that established gas measurement and royalty calculation practicesimproperly deprived the federal government of appropriate natural gas royaltiesand violate 31 U. S. C. 3729 (a) (7) of the False Claims Act.  The cases have been consolidated to theUnited States District Court for the District of Wyoming.  Discovery on the jurisdictional issues isbeing completed to determine if this matter qualifies as a qui tam, or class,action.  The defendants’ joint Motion toDismiss was argued before a Special Master on March 17 and 18, 2005 and,as a result thereof, the Special Master has recommended to the court thatclaims against several of the defendants, including Western, be dismissed. Therecommendation is pending before the court.

 

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

 

***RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS***

 

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

 

**SFAS No. 123(R).**  SFAS No. 123(Revised2004), “*Share Based Payment”,*orSFAS No. 123(R),**was issuedin December 2004 and now must be adopted for annual periods that beginafter June 15, 2005.  Thispronouncement requires companies to expense the fair value of employee stockoptions and other forms of stock based compensation.  We intend to adopt this pronouncement in thefirst quarter of 2006.  Currently, we arecomplying with the pro forma disclosure requirements of SFAS No. 123, *“Accounting for Stock Based Compensation.* SFAS 123(R) provides for various methods ofadoption.  We have not yet determinedwhich method of adoption we will utilize.

 

**SFAS No. 151.**   SFAS No. 151, “*Inventory Costs, an amendment of ARB No. 43,Chapter 4”*was issued in November 2004 and is effective for theCompany for inventory costs incurred in fiscal years beginning after June 15,2005, and will be applied prospectively. SFAS No. 151 amends APB Opinion No. 43, Chapter 4, “InventoryPricing” to clarify the accounting for abnormal amounts of costs and theallocation of fixed production overheads. We will adopt SFAS No. 151 on January 1, 2006 and believe thatthe adoption of this pronouncement will not affect our results of operations,financial position or cash flows.

 

**SFAS No. 153.**   SFAS No. 153, “*Exchanges of Nonmonetary Assets, an amendment of APBOpinion No. 29”*was issued in December 2004 and iseffective for the Company for nonmonetary asset exchanges occurring in fiscalperiods beginning after June 15, 2005, and will be appliedprospectively.  SFAS No. 153 amendsAPB Opinion No. 29, “*Accounting forNonmonetary Transactions”*. The guidance in APB Opinion No. 29 is based on the principle thatexchanges of nonmonetary assets should be measured based on the fair value ofthe assets exchanged but included certain exceptions to that principle.  SFAS No. 153 amends APB Opinion No. 29to eliminate the exception for nonmonetary exchanges of similar productiveassets and replaces it with a general exception for exchanges of nonmonetaryassets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flowsof the entity are expected to change significantly as a result of theexchange.  We adopted SFAS No. 153on July 1, 2005.

 

**EITF No. 04-13.  **At its November 2004meeting, the Emerging Issues Task Force, or EITF, of the FASB began discussionof Issue No. 04-13, “*Accounting forPurchases and Sales of Inventory with the Same Counterparty*.”  This Issue addresses the question of when itis appropriate to measure non-monetary purchases and sales of inventory at fairvalue and record them in cost of sales and revenues and when they should berecorded as an exchange measured at the book value of the item sold. This issueis currently on the agenda for the September 2005 meeting of theEITF.  The implementation of this EITF,if approved, may reduce revenues and related costs but will not have a materialimpact on our results of operations, financial position or cash flows.

 

Inorder to minimize transportation costs or make product available at a locationof our customer’s preference, from time to time, we will enter into arrangementsto buy product from a party at one location and arrange to sell a like quantityof product to this same party at another location.  In accordance with EITF 03-11, we record revenue on these transactions on agross basis versus sales net of purchases basis because we obtain title to theproduct that we buy, bear the risk of loss, credit and performance exposure onthese transactions, and take physical delivery of the product.  For the quarters ended June 30, 2005 and2004, we recorded revenues of $34.6 million and $24.2 million, respectively,and product purchases of $30.8 million and $20.6 million, respectively, fortransactions which were entered into concurrently and with the intent to buyand sell like quantities with the same counterparty at different locations andat market prices at those locations.  Forthe six 

 

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months ended June 30, 2005 and 2004, we recorded revenues of $63.3million and $49.4 million, respectively, and product purchases of $57.5 millionand $44.5 million, respectively, for these types of transactions.

 

**FSPFAS 19-1.**  In April 2005,the FASB Staff issued FASB Staff Position, or FSP, FAS 19-1, “Accountingfor Suspended Well Costs.” This FSP amends SFAS 19, “*Financial Accounting and Reporting by Oil and GasProducing Companies*,” as it pertains to capitalizing the costs ofdrilling exploratory wells pending determination of whether the well has foundproved reserves.  FSP, FAS 19-1 statesthat exploratory well costs should continue to be capitalized if the well hasfound a sufficient quantity of reserves to justify its completion as aproducing well and the entity is making progress assessing reserves and theeconomic and operational viability of the project.  We adopted this FSP in the second quarter of2005, as required, and it did not have a material impact on our results ofoperations, financial position or cash flows.

 

Exploratory lease rentals and geological andgeophysical costs are charged to expense as incurred.  Exploratory drilling costs are capitalizedwhen incurred pending the determination of whether a well has found provedreserves.  A determination of whether awell has found proved reserves is made shortly after drilling is completed. Thedetermination is based on a process that relies on interpretations of availablegeological, geophysical, and engineering data. If an exploratory well is determined to be unsuccessful, the capitalizeddrilling costs will be charged to expense in the period the determination ismade.  If an exploratory well requires amajor capital expenditure before production can begin, the cost of drilling theexploratory well will continue to be carried as an asset pending determinationof whether proved reserves have been found only as long as: i) the well hasfound a sufficient quantity of reserves to justify its completion as aproducing well if the required capital expenditure is made, and ii) drilling ofadditional exploratory wells is under way or firmly planned for the nearfuture. If the drilling of additional exploratory wells in the area is notunder way or firmly planned, or if the well has not found a commerciallyproducible quantity of reserves, the exploratory well is assumed to beimpaired, and its costs are charged to expense.

 

The following tablereflects the net changes in capitalized exploratory well costs during the sixmonths ended June 30, 2005 (000s).

 
| ** **                                                                                            | ** ** | **Six Months Ended June 30, 2005** | ** ** |
|-------------------------------------------------------------------------------------------------------|------------|-----------------------------------------|------------|
| Beginning  balance at December 31, 2004                                                          |       | $                                       | 48,546     |   |
| Additions to  capitalized exploratory well costs pending the determination of proved  reserves        |       | 37,613                                  |       |
| Reclassifications  to wells, facilities, and equipment based on the determination of proved  reserves |       | (4,290                                  | )          |
| Capitalized  exploratory well costs charged to expense                                                |       | (1,599                                  | )          |
| Ending balance                                                                                        |       | $                                       | 80,270     |   |

 

Substantially all of ourexploratory wells that have been capitalized for a period greater than one yearare located in the Powder River Basin. In this basin, we drill wells into various coal seams.  In order to produce gas from the coal seams,a period of dewatering lasting from a few to twenty-four months, or in somecases longer, is required prior to obtaining sufficient gas production tojustify capital expenditures for compression and gathering, and to classify thereserves as proven.  In order toaccelerate the dewatering time, we drill additional exploratory wells in theseareas.

 

**FASB Interpretation No. 47. **FASB Interpretation No. 47,“*Accounting for Conditional Asset RetirementObligations*, *an interpretation ofFASB Statement No. 143*”, or FIN 47, was issued in March 2005and is effective in fiscal periods beginning after December 31, 2005.  FIN 47 clarifies the term “conditional assetretirement obligation” as used in FASB Statement 143, “Accounting for AssetRetirement Obligations”.  Conditionalasset retirement obligations as used in FASB Statement 143 refers to a legalobligation to perform an asset retirement activity in which the timing and (or)method of settlement are conditional on a future event that may or may not bewithin the control of the entity. The obligation to perform an asset retirementactivity is unconditional even though uncertainty exists about the timing and(or) method of settlement. Accordingly, an entity is required to recognize aliability for the fair value of a conditional asset retirement obligation ifthe fair value of the liability can be reasonably estimated. When sufficientinformation exists, uncertainty about the timing and (or) method of settlementshould be factored into the measurement of the liability. We will adopt thisinterpretation on January 1, 2006 and do not expect the pronouncement tohave a material impact on our results of operation, financial position or cashflows.

 

**SFAS No. 154.**   In May 2005,the FASB issued SFAS No. 154, “*AccountingChanges and Error Corrections, a replacement of Accounting Principles BoardOpinion (APB) No. 20, Accounting Changes, and FASB Statement No. 3,*

 

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*ReportingAccounting Changes in Interim Financial Statements*.” This Statement requires retrospectiveapplication to prior periods’ financial statements of a change in accountingprinciple. It applies both to voluntary changes and to changes required by anaccounting pronouncement if the pronouncement does not include specifictransition provisions. APB 20 previously required that most voluntary changesin accounting principles be recognized by recording the cumulative effect of achange in accounting principle. SFAS 154 is effective for fiscal yearsbeginning after December 15, 2005. We plan to adopt this statement on January 1,2006 and it is not expected to have a material effect on the financialstatements upon adoption.

 

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| **ITEM 2.** | **MANAGEMENT’S  DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS** |
|-------------|-------------------------------------------------------------------------------------------------|

 

The following discussion and analysis relates to factors that haveaffected our consolidated financial condition and results of operations for thethree and six months ended June 30, 2005 and 2004.  Certain prior year amounts have beenreclassified to conform to the presentation used in 2005.  You should also refer to our interimconsolidated financial statements and notes thereto included elsewhere in thisdocument.  This section, as well as othersections in this Form 10-Q/A, contain “forward-looking statements” withinthe meaning of the Private Securities Litigation Reform Act of 1995, which canbe identified by the use of forward-looking terminology, such as “may,” “intend,”“will,” “expect,” “anticipate,” “estimate,” or “continue” or the negativethereof or other variations thereon or comparable terminology.  In addition to the important factors referredto herein, numerous factors affecting the gas processing industry generally andin the specific markets for gas and NGLs in which we operate could cause actualresults to differ materially from those in such forward-looking statements.

 

***Restatement of Previously Issued FinancialStatements***

 

Upon adoption of FAS 133 in 2001, we analyzed our gasstorage and gas transportation contracts in detail, and determined that thesecontracts had the characteristics of a derivative under generally acceptedaccounting principles. On November 21, 2005, we announced that our managementand our audit committee had completed a review of the accounting treatment ofour gas storage and gas transportation contracts and determined that thesecontracts do not meet the definition of a derivative.  Specifically, after a detailed review of thecontracts and the market for those contracts, we subsequently determined thatthese contracts do not meet the definition of a derivative as: (i) themarket for these types of contracts is not sufficiently liquid for us toreceive fair value in a ready market and (ii) if any contract is assigned,there is no assurance that we will be relieved of our rights and obligationsunder that contract.

 

Historically,the non-cash mark-to-market valuation of the gas storage and transportationcontracts which, prior to the restatement were considered to be derivatives,effectively offset non-cash mark-to-market changes to the future salederivatives for our stored or transported natural gas.  Without this offsetting valuation, thenon-cash mark-to-market of the future sale derivative contracts on the sale ofgas will fluctuate through earnings with changes in market prices and will notbe offset by a corresponding mark to market on the gas storage andtransportation contracts which are no longer derivatives.  As the stored or transported natural gas issold and the forward derivatives are settled, we will realize the benefit ofthe storage and transportation transactions through earnings.

 

The effect of the restatement for each of the threeand six months ending June 30, 2005 and 2004 is as follows. Additionalinformation on the nature and impact of these accounting corrections isprovided in the Notes to Consolidated Financial Statements included elsewherein this Form 10-Q/A (amounts in thousands, except per share amounts):

 
| ** **                            | ** ** | **Three  months ending** | ** ** | **Six  months ending**  | ** ** |
|---------------------------------------|------------|--------------------------|------------|-------------------------|------------|
| ** **                            | ** ** | **June 30,  2005**  | ** ** | **June 30,  2004** | ** ** | **June 30,  2005** | ** ** | **June 30,  2004** | ** ** |
| ** **                            | ** ** | **As**                   | ** ** | **As**                  | ** ** | **As** | ** ** | **As** | ** ** | **As** | ** ** | **As** | ** ** | **As** | ** ** | **As** | ** ** |
| ** **                            | ** ** | **Reported**             | ** ** | **Restated**            | ** ** | **Reported** | ** ** | **Restated** | ** ** | **Reported** | ** ** | **Restated** | ** ** | **Reported** | ** ** | **Restated** | ** ** |
| Total revenues                        |       | $                        | 861,196    |                    | $          | 868,026 |   | $ | 726,304 |   | $ | 725,838 |   | $ | 1,715,511 |   | $ | 1,702,133 |   | $ | 1,497,519 |   | $ | 1,505,518 |   |
| Income before  taxes                  |       | 52,668                   |       | 59,498                  |       | 26,592 |   | 26,126 |   | 104,010 |   | 90,632 |   | 64,973 |   | 72,972 |   |
| Net income                            |       | 33,318                   |       | 37,629                  |       | 13,976 |   | 13,649 |   | 65,946 |   | 57,335 |   | 43,063 |   | 48,083 |   |
| Earnings per  share-assuming dilution |       | 0.44                     |       | 0.50                    |       | 0.19 |   | 0.18 |   | 0.87 |   | 0.76 |   | 0.58 |   | 0.65 |   |
| Cash flow from  operating activities  |       | $                        | 42,706     |                    | $          | 42,706 |   | $ | (36,364 | ) | $ | (36,364 | ) | $ | 160,102 |   | $ | 160,102 |   | $ | 88,132 |   | $ | 88,132 |   |

 

***COMPANYOVERVIEW***

 

***Business Strategy. *** Maximizing the value of our existing coreassets is the focal point of our business strategy.  Our core assets are our fully integratedupstream and midstream assets in the Powder River and Greater Green RiverBasins in Wyoming, the San Juan Basin in New Mexico, and our midstreamoperations in west Texas and Oklahoma. Our long-term

 

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business plan is to increase stockholder value by: (i) doublingproven natural gas reserves and equity production of natural gas from thelevels achieved in 2001 over a five year period; (ii) meeting or exceedingthroughput projections in our midstream operations; and (iii) optimizingannual returns.

 

***Industry and Company Overview.  ***In North America, ourindustry has experienced several consecutive years of declining natural gasproduction despite increased drilling activity. Most of the major gas producing areas, such as the Gulf of Mexico, aremature and are in production decline. Our efforts, while concentrated in the Rocky Mountain area, extend intoa variety of diverse unconventional gas plays, where there are estimated to belarge quantities of undeveloped gas.  Weare well positioned for future production growth with a large inventory ofundeveloped drilling locations in the Powder River, the Greater Green River andSan Juan Basins to meet the growing demand for clean burning natural gas.  In addition, our exploration effort leveragesoff of our upstream and midstream expertise in unconventional natural gasresource plays in order to add new company-building projects and to position usfor long-term growth.

 

In theUnited States, the federal government largely retains the mineral rights to theundeveloped reserves in the areas in which we are active; accordingly, thedevelopment and production of these reserves requires permits from federalgovernmental agencies including the Bureau of Land Management, or BLM, andstate agencies such as the Wyoming Department of Environmental Quality, orDEQ.  A significant challenge indeveloping these reserves is the difficulty encountered by the industry inobtaining the required permits in a timely manner.  We believe that our technical expertise indeveloping environmentally responsible solutions to the problems encountered inthe development of gas reserves will be a competitive advantage in overcomingthis challenge.

 

Additionally,to date we have been successful in obtaining drilling rigs and related oilfield services to accomplish our drilling plans.  However, we believe that as we expand intonew areas and continue the development of the areas in which we currentlyparticipate, obtaining rigs, related services and experienced employees in atimely manner will become increasingly difficult.

 

Our operationsare conducted through the following four business segments:

 

***Exploration and Production. ***We explorefor, develop and produce natural gas reserves independently and to enhance andsupport our existing gathering and processing operations. Our producingproperties are primarily located in the Powder River, Greater Green River, SanJuan, and Sand Wash Basins.  These playsprovide low geologic risk, and are multi-year development projects.  These provide us with the opportunity tosteadily increase our production volume over time at reasonable operating andlow finding and development costs.  Inthe second quarter of 2005, our average production sold was 167 MMcfe per day,which is a 13% increase over the daily average production volume sold in thesecond quarter of 2004.

 

Wecontinue to seek to add additional upstream core projects that are focused onRocky Mountain natural gas.  We willutilize our expertise in exploration and low-risk development of unconventionalgas reservoirs including tight-gas sands, coal bed methane, biogenic, and shalegas plays to evaluate acquisitions of either additional leaseholds, proven andundeveloped reserves or companies with operations primarily focused in theRockies.  We may also evaluateunconventional gas reservoirs in areas outside the Rockies where we canleverage our related exploration, production and gathering expertise.  In January 2005, we opened an office inCalgary, Alberta, Canada to evaluate opportunities in the Western CanadianSedimentary Basin.  Overall, at June 30,2005, we have acquired the drilling rights on approximately 1.6 million netacres in various Rocky Mountain basins and continue to expand our leaseholdpositions.

 

***Gathering, Processing and Treating. ***Our core operations are in well-established areassuch as the Permian, Anadarko, Powder River, Greater Green River, and San JuanBasins.  We connect natural gas from gasand oil wells to our gathering systems for delivery to our processing ortreating plants under contracts with terms ranging from one month to the lifeof the lease. At our plants we process natural gas to extract NGLs and treatnatural gas in order to meet pipeline specifications.  We provide these services to major oil andgas companies, to independent producers of various sizes and for our ownproduction.  We believe that our low costof operations, our high on-line time and our safety records are key elements inour ability to compete effectively and provide reliable service to our customers.  Our expertise in gathering, processing andtreating operations can enhance the economics of developing new upstreamprojects.

 

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

 

23

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

 

***Marketing. ***The primary goalof our gas-marketing segment is to ensure that the product from ourprocessing facilities and upstream activities is delivered timely to themarket.  Additionally, our gas marketingoperations seek to preserve and enhance the value received for our equityvolumes of natural gas.  This goal isachieved through the use of hedges on the production of our equity natural gasand NGLs and through the use of firm transportation capacity.  We also buy and sell natural gas and NGLs inthe wholesale market in the United States and in Canada.  These third-party sales, our firmtransportation capacity on interstate pipelines and our gas storage positions,combined with the stable supply of gas from our facilities and production,enable us to respond quickly to changing market conditions and to takeadvantage of seasonal price variations and peak demand periods.

 

***RESULTS OF OPERATIONS***

 

**Three andsix months ended June 30, 2005 compared to the three and six months ended June 30,2004**

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

 
| ** **                                          | ** ** | **Restated**            | ** ** | **Restated** | ** ** |
|-----------------------------------------------------|------------|-------------------------|------------|--------------|------------|
| ** **                                          | ** ** | **Three  Months Ended** | ** ** | ** **   | ** ** | **Six  Months Ended** | ** ** | ** ** | ** ** |
| ** **                                          | ** ** | **June 30,**       | ** ** | **Percent**  | ** ** | **June 30,** | ** ** | **Percent** | ** ** |
| ** **                                          | ** ** | **2005**                | ** ** | **2004**     | ** ** | **Change** | ** ** | **2005** | ** ** | **2004** | ** ** | **Change** |   |
| **Financial results:**                              |       |                    |       |         |       |   |   |   |   |   |   |   |   |
| Revenues                                            |       | $                       | 868,026    |         | $          | 725,838 |   | 20 |   | $ | 1,702,133 |   | $ | 1,505,518 |   | 13 |   |
| Net income                                          |       | 37,629                  |       | 13,649       |       | 176 |   | 57,335 |   | 48,083 |   | 19 |   |
| Earnings per share of common  stock                 |       | 0.51                    |       | 0.19         |       | 168 |   | 0.77 |   | 0.67 |   | 15 |   |
| Earnings per share of common stock - diluted        |       | 0.50                    |       | 0.18         |       | 178 |   | 0.76 |   | 0.65 |   | 17 |   |
| Net cash (used in) provided by operating activities |       | 42,706                  |       | (36,364      | )          | 217 |   | 160,102 |   | 88,132 |   | 82 |   |
| Net cash (used in) investing activities             |       | (76,847                 | )          | (42,529      | )          | 81 |   | (191,088 | ) | (77,655 | ) | 146 |   |
| Net cash (used in) provided by financing activities |       | $                       | 38,454     |         | $          | 50,012 |   | (23 | ) | $ | 36,634 |   | $ | (33,707 | ) | 209 |   |
|                                                |       |                    |       |         |       |   |   |   |   |   |   |   |   |
| **Operating data:**                                 |       |                    |       |         |       |   |   |   |   |   |   |   |   |
| Average gas sales (MMcf/D)                          |       | 1,162                   |       | 1,190        |       | (2 | ) | 1,231 |   | 1,279 |   | (4 | ) |
| Average NGL sales (MGal/D)                          |       | 1,876                   |       | 1,643        |       | 14 |   | 1,819 |   | 1,627 |   | 12 |   |
| Average gas prices ($/Mcf)                          |       | $                       | 6.38       |         | $          | 5.49 |   | 16 |   | $ | 6.13 |   | $ | 5.40 |   | 14 |   |
| Average NGL prices ($/Gal)                          |       | $                       | 0.88       |         | $          | 0.68 |   | 29 |   | $ | 0.86 |   | $ | 0.66 |   | 30 |   |

 

Net income increased $24.0 million for the three monthsended June 30, 2005, compared to the same period in 2004.  The increase in net income was primarilyattributable to higher production of equity gas volumes, higher commodityprices in the second quarter of 2005, andmark-to-market non-cash gains from our price risk management activitiesrelated to our future sales of gasutilizing our gas storage and gas transportation capacity.  In addition, the second quarter of 2004 wasnegatively impacted by an after-tax charge associated with a settlement withthe CFTC of $7.0 million, and an after-taxcharge associated with the early extinguishment of long-term debt of $6.7million.  In the second quarter of2005, we had an increase in operating costs and depreciation, depletion andamortization and an after-tax charge of $3.8 million recorded in connectionwith a settlement of litigation.

 

Net income increased $9.3 million for the six monthsended June 30, 2005, compared to the same period in 2004. This increasewas primarily attributable to higher production of equity gas volumesand higher commodity prices, offset in part by mark-to-market non-cash losses from our price risk managementactivities related to our future sales ofgas utilizing our storage and transportation capacity.  In addition, the first six months of 2004were negatively impacted by the 2004 settlementwith the CFTC, and the 2004 early extinguishment of long-term debt.  Partially offsetting these items in the 2004period was the cumulative effect of a change in accountingprinciple.  Effective as of January 1,2004, we revised our depreciation and depletion methodology for our oil and gasproperties.  This change in accountingprinciple resulted in a cumulative reduction of depreciation for periods priorto 2004 of $4.7 million, net of tax, in 2004.

 

Revenuesfrom the sale of gas increased $82.2 million to $678.1 million for the threemonths ended June 30, 2005 compared to the same period in 2004.  This increase was primarily due to asignificant increase in product prices, which more than offset a decrease insales volume of third-party product in the three months ended June 30,2005 compared to the same period in 2004. Average gas prices realized by us increased $0.89 per Mcf to $6.38 perMcf for the quarter ended June 

 

24

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30, 2005 compared to the same period in 2004.  Included in the realized gas price wereapproximately $446,000 of gains recognized in the three months ended June 30,2005 related to futures positions on equity gas volumes.  We have entered into additional futurespositions for approximately 60% of our equity gas for the remainder of 2005 andto a lesser extent in 2006.  See furtherdiscussion in “Item 3. Quantitative and Qualitative Disclosures About MarketRisk.”  Average gas sales volumesdecreased slightly to 1,162 MMcf per day for the quarter ended June 30,2005 compared to the same period in 2004.

 

Revenuesfrom the sale of gas increased $113.1 million to $1,374.3 million for the sixmonths ended June 30, 2005 compared to the same period in 2004.  This increase was primarily due to asignificant increase in product prices, which more than offset a decrease insales volume of third-party product in the six months ended June 30, 2005,compared to the same period in 2004. Average gas prices realized by us increased $0.73 per Mcf to $6.13 perMcf for the six months ended June 30, 2005 compared to the same period in2004.  Included in the realized gas pricewere approximately $1.8 million of gains recognized in the six months ended June 30,2005 related to futures positions on equity gas volumes.  We have entered into additional futurespositions for approximately 60% of our equity gas for the remainder of 2005 andto a lesser extent in 2006.  See furtherdiscussion in “Item 3. Quantitative and Qualitative Disclosures About MarketRisk.”  Average gas sales volumesdecreased slightly to 1,231 MMcf per day for the six months ended June 30,2005 compared to the same period in 2004.

 

Revenuesfrom the sale of NGLs increased $47.5 million to $149.5 million for the threemonths ended June 30, 2005 compared to the same period in 2004.  This is primarily due to a significantincrease in product prices and an increase in sales volumes.  Average NGL prices realized by us increased$0.20 per gallon to $0.88 per gallon for the three months ended June 30,2005 compared to the same period in 2004. Included in the realized NGL price were approximately $1.1 million oflosses recognized in the three months ended June 30, 2005 related tofutures positions on equity NGL volumes. We have entered into additional futures positions for approximately 30%of our equity NGL production for the remainder of 2005 and to a lesser extentin 2006.  See further discussion in “Item3. Quantitative and Qualitative Disclosures About Market Risk.”  Average NGL sales volumes increased 233 MGalper day to 1,876 MGal per day for the three months ended June 30, 2005compared to the same period in 2004. This increase is due to the acquisition of several facilities in February 2005.

 

Revenuesfrom the sale of NGLs increased approximately $87.5 million to $282.5 millionfor the six months ended June 30, 2005 compared to the same period in2004.  This is primarily due to asignificant increase in product prices and an increase in sales volumes.  Average NGL prices realized by us increased$0.20 per gallon to $0.86 per gallon for the six months ended June 30,2005 compared to the same period in 2004. Included in the realized NGL price were approximately $1.9 million oflosses recognized in the six months ended June 30, 2005 related to futurespositions on equity NGL volumes.  We haveentered into additional futures positions for approximately 30% of our equityNGL production for the remainder of 2005 and to a lesser extent in 2006.  See further discussion in “Item 3.Quantitative and Qualitative Disclosures About Market Risk.”  Average NGL sales volumes increased 192 MGalper day to 1,819 MGal per day for the six months ended June 30, 2005compared to the same period in 2004. This increase is due to the acquisition ofseveral facilities in February 2005.

 

Theeffect of Price risk management activities changed from $3.0 million for thequarter ended June 30, 2004 to $11.2 million for the quarter ended June 30,2005.  This change was due to thenon-cash mark-to-market of our risk management activities.  This account is primarily impacted by changesin the forward price of natural gas in the 2005 quarter as compared to 2004quarter and the impact of those price changes on the fair value of the forward salederivatives for our gas in storage.

 

Theeffect of Price risk management activities changed from $6.0 million for thesix months ended June 30, 2004 to ($9.0) million for the six months ended June 30,2005.  This change was due to thenon-cash mark-to-market of our risk management activities.  This account is primarily impacted by changesin the forward price of natural gas in the 2005 period as compared to 2004period and the impact of those price changes on the fair value of the forwardsale derivatives for our gas in storage.

 

Productpurchases increased by $105.4 million and $155.4 million for the quarter andsix months ended June 30, 2005, respectively, compared to the same periodsin 2004.  These increases in productpurchases were the result of higher product prices.  Overall, combined product purchases as apercentage of sales of all products was 86% in both the quarter ended June 30,2005 and 2004.  Combined productpurchases as a percentage of sales of all products decreased to 85% for the sixmonths ended June 30, 2005 from 86% in 2004.  The reduction in this percentage is primarilythe result of a decrease in the sale of third party product and an increase inthe sale of equity production.

 

Plantand transportation operating expense increased by $4.6 million and $10.3million, respectively, for the three and six months ended June 30, 2005compared to the same periods in 2004. The increase for the quarter ended June 30, 2005 as 

 

25

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compared to the same period in 2004 was substantially due to increasedproperty tax, labor and repairs and maintenance expenses and the October 2004and February 2005 asset acquisitions. The increase for the six monthsended June 30, 2005 as compared to the same period in 2004 wassubstantially due to increased property tax, labor and third-party gatheringexpenses and the October 2004 and February 2005 asset acquisitions.

 

Oiland gas exploration and production expense increased by $4.2 million and $12.0million, respectively, for the three and six months ended June 30, 2005compared to the same periods in 2004. The increase for the quarter ended June 30, 2005 as compared to thesame period in 2004 was substantially due to increased production taxes andexpenses associated with the San Juan properties acquired in October 2004.The increase for the six months ended June 30, 2005 as compared to thesame period in 2004 was substantially due to increased lease operatingexpenses, or LOE, in the Powder River Basin coal bed development and expensesassociated with the San Juan properties acquired in 2004. Overall, LOE averaged$0.80 per Mcf and $0.83 per Mcf for the quarter and six months ended June 30,2005 and LOE in the Powder River Basin coal bed development averaged $0.92 perMcf and $0.89 per Mcf in the quarter and six months ended June 30, 2005,respectively.  In the Powder River Basin,these represent increases of $0.14 and $0.10 per Mcf from the same periods in2004.  The increase in LOE per Mcf in thePowder River Basin is substantially due to higher water handling charges ondewatering wells in several new pilot areas that have no offsetting gasproduction as yet, contract labor, and fuel and operating costs of wellheadblowers in the Powder River Basin as well as increased costs related toinitiating operations of the San Juan Basin production assets.

 

Depreciation, depletion and amortization increased by$8.5 million and $14.9 million, respectively, for the three and six monthsended June 30, 2005 as compared to the same periods in 2004.  For the quarter ended June 30, 2005 ascompared to the same period in 2004, we had a $2.4 million increase in DD&Ain our midstream operations primarily due to our expanding CBM gathering systemin the Powder River Basin and the October 2004 acquisition of additionalmidstream assets in the San Juan Basin, and a $6.0 million increase in DD&Ain our upstream operations primarily due to our continued development in thePowder River Basin, downward revisions to reserves in the Powder River Basinbased on the December 2004 reserve report, and our October 2004acquisition of producing properties in the San Juan Basin.  For the six months ended June 30, 2005as compared to the same period in 2004, we had a $4.7 million increase inDD&A in our midstream operations and a $10.6 million increase in ourupstream operations primarily due to those items mentioned above.

 

Sellingand administrative expenses increased by $282,000 and $2.9 million for thethree and six months ended June 30, 2005 as compared to the same period in2004.  The increase in selling andadministrative expenses for the six months ended June 30, 2005 as comparedto 2004 was primarily the result of increased administrative salaries,insurance, audit expenses, and compensation expense related to our restrictedstock plan.  Additionally, a charge of$5.9 million was recorded in the second quarter of 2005 in connection with asettlement of litigation and a charge associated with a settlement with theCFTC of $7.0 million was recorded in the second quarter of 2004.

 

TheTotal provision for income taxes, as a percentage of Income before taxes wasapproximately 36.7% and 36.6%, respectively, during the quarter and six monthsended June 30, 2005 as compared to 47.4% and 41.0%, respectively, in sameperiods of 2004.  This decrease is due tothe civil penalty paid to the CFTC in 2004, which was non-deductible for taxpurposes.

 

***Cash FlowInformation***

 

Cashflows from operating activities increased by $72.0 million in the first sixmonths of 2005 compared to the same period in 2004. This increase was primarilydue to the increase in net income and the timing of cash receipts and payables.

 

Cashflows used in investing activities increased by $113.4 million in the first sixmonths of 2005 compared to the same period in 2004.  This increase was primarily due to anincreased level of capital expenditures including the February 2005acquisition of additional midstream assets in the Greater Green River Basin.

 

Cashflows used in financing activities decreased by $70.3 million in the first sixmonths of 2005 compared to the same period in 2004.  This decrease was due to a significantreduction in our outstanding debt in the first six months of 2004, as comparedto the utilization of funds provided by financing activities to fund ourcapital investments in 2005.

 

***SegmentInformation***

 

***GasGathering, Processing and Treating.***  The Gas Gathering, Processing and Treatingsegment realized segment-operating profit of $103.2 million for the six monthsended June 30, 2005 compared to $78.5 million in the same period in2004.  The increase in operating profitin this segment in the 2005 periods is primarily due to higher realized pricesand the resulting increase in net margin as shown below.  

 

26

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| ** **                                                  | ** ** | **Quarter Ended  June 30,** | ** ** | **Six Months Ended  June 30,** | ** ** |
|-------------------------------------------------------------|------------|----------------------------------|------------|-------------------------------------|------------|
| ** **                                                  | ** ** | **2005**                         | ** ** | **2004**                            | ** ** | **2005** | ** ** | **2004** | ** ** |
| Gross Margin  ($/Mcf)(1)                                    |       | $                                | 0.60       |                                | $          | 0.53 |   | $ | 0.62 |   | $ | 0.51 |   |
| Segment Plant  operating and transportation expense ($/Mcf) |       | 0.20                             |       | 0.18                                |       | 0.21 |   | 0.18 |   |
| Net Margin  ($/Mcf)                                         |       | 0.40                             |       | 0.35                                |       | 0.41 |   | 0.33 |   |
| Average gas  volumes gathered (MMcf/D)                      |       | 1,394                            |       | 1,314                               |       | 1,375 |   | 1,313 |   |
|                                                             |            |                                  |            |                                     |            |  |  |  |  |  |  |  |  |

 

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

 

***Explorationand Production.*** The Exploration and Production segment realized segment -operatingprofit of $86.5 million for the six months ended June 30, 2005 compared to$69.7 million in 2004. The increase is due to increased equity production,higher product prices, and the acquisition of production assets in the San Juanbasin in the fourth quarter of 2004. During the first six months of 2005, our production of natural gas ascompared to the same period in 2004 increased by 13% to 29.9 Bcfe.  The following table sets forth the averagesales price received for our oil and gas products in the quarter and six monthsended June 30, 2005 and 2004.

 
| ** **                                              | ** ** | **Quarter Ended  June 30,** | ** ** | **Six Months Ended  June 30,** | ** ** |
|---------------------------------------------------------|------------|----------------------------------|------------|-------------------------------------|------------|
| ** **                                              | ** ** | **2005**                         | ** ** | **2004**                            | ** ** | **2005** | ** ** | **2004** | ** ** |
| Average sales  price: (1)                               |       |                             |       |                                |       |   |   |   |   |
| Oil ($/Bbl)                                             |       | $                                | 47.88      |                                | $          | 33.89 |   | $ | 45.58 |   | $ | 33.68 |   |
| Gas ($/Mcf),  excluding the effect of hedging positions |       | 5.34                             |       | 4.59                                |       | 5.11 |   | 4.49 |   |
| Gas ($/Mcf),  including the effect of hedging positions |       | 5.36                             |       | 4.71                                |       | 5.17 |   | 4.61 |   |
|                                                    |       |                             |       |                                |       |   |   |   |   |
| Production and  other costs:                            |       |                             |       |                                |       |   |   |   |   |
| Lease operating  expense ($/Mcfe)                       |       | 0.80                             |       | 0.66                                |       | 0.83 |   | 0.65 |   |
| Production tax  expense ($/Mcfe)                        |       | 0.59                             |       | 0.48                                |       | 0.53 |   | 0.50 |   |
| Gathering and  transportation expense ($/Mcfe)          |       |                             |       |                                |       |   |   |   |   |
| Inter-segment  charges                                  |       | 0.60                             |       | 0.53                                |       | 0.61 |   | 0.59 |   |
| Third-party  charges                                    |       | 0.16                             |       | 0.20                                |       | 0.18 |   | 0.13 |   |
| Other expenses  ($/Mcfe)                                |       | 0.04                             |       | 0.02                                |       | 0.02 |   | 0.01 |   |
| Total costs  ($/Mcfe)                                   |       | $                                | 2.19       |                                | $          | 1.89 |   | $ | 2.17 |   | $ | 1.88 |   |

 

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

 

***Marketing.***  The Marketing segment realized segment-operatingloss of $8.2 million for the six months ended June 30, 2005 compared to asegment-operating profit of $14.3 million in the same period of 2004.  The decrease was due to lower pricedifferentials between the Rocky Mountain and Mid Continent market centers,which reduced the Marketing segment’s ability to capitalize on ourtransportation contracts, and by non-cashmark-to-market losses from our price risk management activities relatedto our future sales of gas utilizing ourstorage and transportation capacity.  Asthe stored or transported natural gas is sold and the future sale derivativesare settled, we will realize the benefit of the storage and transportationtransactions through earnings in the quarter in which the gas is physicallysold.

 

***Transportation.***  The Transportation segment realizedsegment-operating profit of $6.3 million for the six months ended June 30,2005 compared to $4.9 million in the same period of 2004.  The Transportation segment includes theresults from the MIGC and MGTC pipelines in the Powder River Basin.

 

***RecentlyIssued Accounting Pronouncements.***  We continually monitor and revise ouraccounting policies as new rules are issued.  See Notes to Consolidated FinancialStatements (Unaudited) in Item 1 of this Form 10-Q/A for a detaileddescription of recently issued accounting pronouncements.

 

#### ***LIQUIDITY AND CAPITAL RESOURCES***

#### ** **

#### **Our sources of liquidity and capital resourceshistorically have been net cash provided by operating activities, fundsavailable under our financing facilities and proceeds from offerings of debtand equity securities.  In the past,these sources have been sufficient to meet our needs and finance the growth ofour business.  We can give no assurancethat the historical sources of liquidity and capital resources will beavailable for future development and acquisition projects, and we may berequired to seek additional or alternative financing sources.  Product prices, hedges of equity production,sales of inventory, the volume of natural gas processed by our facilities, thevolume of natural gas produced from our producing properties, the**

 

27

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#### **margin on third-party productpurchased for resale, as well as the timely collection of our receivables areall expected to have significant influences on our future net cash provided byoperating activities.  Additionally, ourfuture growth will be dependent upon obtaining additions to dedicated plantreserves, acquisitions, new project development, marketing results, efficientoperation of our facilities and our ability to obtain financing at favorableterms.**

#### ** **

During the pastseveral years, we have been successful in developing additionalreserves of natural gas and increasing our equity natural gas production.  However, the overall level of drilling andproduction associated with our producing properties will depend upon, amongother factors, the price for gas, availability of transportation capacity tomarket centers, the energy and environmental policy and regulation bygovernmental agencies, the 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.  A significant reduction in the level of ourproduction or a significant reduction in natural gas prices could have amaterial adverse effect on our financial condition, results of operations andcash flows.

 

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

 

We believe that the amounts available to beborrowed under our financing facilities, together with net cash provided byoperating activities, will provide us with sufficient funds to connect newreserves, maintain our existing facilities and complete our current capitalexpenditure program.  Depending on thetiming and the amount of our future projects, we may be required to seekadditional sources of capital.  Ourability to secure such capital is restricted by our financing facilities,although we may request additional borrowing capacity from our lenders, seekwaivers from our lenders to permit us to borrow funds from third parties, seekreplacement financing facilities from other lenders, use stock as a currencyfor acquisitions, sell existing assets or use a combination of alternatives.  While we believe that we would be able tosecure additional financing, if required, we can provide no assurance that wewill be able to do so or as to the terms of any additional financing.  In July 2005, we utilized amountsavailable under our revolving credit facility to fund a scheduled principalrepayment of $10.0 million under our master shelf agreement.

 

***Sources and Uses of Funds*.**  Our sources and uses of funds for the sixmonths ended June 30, 2005 are summarized as follows (dollars inthousands):

 
| **Sources  of funds:**                                           |   |    |      |
|------------------------------------------------------------------|--------|---------|-----------|
| Borrowings under  our revolving credit facility                  |   | $       | 1,789,015 |   |
| Borrowings under  our master shelf agreement                     |   | 25,000  |      |
| Proceeds from  the dispositions of property and equipment        |   | 1,411   |      |
| Net cash  provided by operating activities                       |   | 160,102 |      |
| Distributions  from equity investments                           |   | 613     |      |
| Change in  outstanding checks                                    |   | 6,335   |      |
| Proceeds from  exercise of common stock options                  |   | 2,735   |      |
| Total sources of  funds                                          |   | $       | 1,985,211 |   |
| **Uses of funds:**                                               |   |    |      |
| Payments related  to long-term debt (including debt issue costs) |   | $       | 1,754,055 |   |
| Capital  expenditures                                            |   | 193,112 |      |
| Payments made  under our master shelf agreement                  |   | 25,000  |      |
| Common dividends  paid                                           |   | 7,396   |      |
| Total uses of  funds                                             |   | $       | 1,979,563 |   |

 

28

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***Capital Investment Program.***  We currently anticipate capital expendituresin 2005 of approximately $376.4 million. Overall, capital expenditures in the Powder River Basin CBM developmentand in the Greater Green River Basin operations represent 34% and 29%, respectively,of the total 2005 budget.  Due todrilling and regulatory uncertainties that are beyond our control, we can makeno assurance that our capital budget for 2005 will not change or that we willactually incur this level of capital expenditures.  This budget may be increased to provide foracquisitions if approved by our board of directors.

 

The2005 capital budget and our capital expenditures during the six months ended June 30,2005 are presented in the following table (dollars in millions):

 
| **Type of Capital Expenditure**                              | ** ** | **2005 Capital Budget** | ** ** | **Year to Date  Capital Expenditures** | ** ** |
|--------------------------------------------------------------|------------|------------------------------|------------|----------------------------------------|------------|
| Gathering, processing, treating and pipeline assets  (1)     |       | $                            | 132.8      |                                   | $          | 61.5 |   |
| Exploration and production and lease acquisition  activities |       | 204.3                        |       | 102.8                                  |       |
| Acquisition of Greater Green River Basin midstream  assets   |       | 28.0                         |       | 28.0                                   |       |
| Information technology and other items                       |       | 3.0                          |       | 2.4                                    |       |
| Capitalized interest and overhead                            |       | 8.3                          |       | 6.0                                    |       |
| Total Capital  Expenditures                                  |       | $                            | 376.4      |                                   | $          | 200.7 |   |

 

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(1) Includes $13.7million budgeted in 2005 and $3.0 million expended in the six months ended June 30,2005 for maintaining existing facilities.

 

***Contractual Commitmentsand Obligations***

 

##### ***Contractual Cash Obligations. ***Asummary of our contractual cash obligations as of June 30, 2005 is asfollows (dollars in thousands):

 
| ** **                                | ** ** | ** **             | ** ** | **Payments by Period** | ** ** |
|-------------------------------------------|------------|------------------------|------------|------------------------|------------|
| **Type of Obligation**                    | ** ** | **Total  Obligations** | ** ** | **Due in  2005**       | ** ** | **Due in  2006 – 2007** | ** ** | **Due in  2008 – 2009** | ** ** | **Due  Thereafter** | ** ** |
| Guarantee of Fort Union Project Financing |       | $                      | 4,316      |                   | $          | 439 |   | $ | 1,931 |   | $ | 1,946 |   | $ | — |   |
| Operating Leases                          |       | 78,616                 |       | 8,900                  |       | 32,871 |   | 25,037 |   | 11,808 |   |
| Firm Transportation Capacity Agreements   |       | 232,468                |       | 19,547                 |       | 72,325 |   | 59,440 |   | 81,156 |   |
| Firm Storage Capacity Agreements          |       | 30,198                 |       | 4,621                  |       | 11,605 |   | 5,045 |   | 8,927 |   |
| Long-term Debt                            |       | 417,000                |       | 10,000                 |       | 20,000 |   | 262,000 |   | 125,000 |   |
| Interest on Long-term Debt (1)            |       | 98,780                 |       | 10,495                 |       | 39,995 |   | 32,399 |   | 15,891 |   |
| Total Contractual Cash Obligations        |       | $                      | 861,378    |                   | $          | 54,002 |   | $ | 178,727 |   | $ | 385,867 |   | $ | 242,782 |   |

 

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(1) The interestrate assumed on the revolving credit facility at June 30, 2005 is 4.5% perannum.

 

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

 

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

 

***Firm Transportation Capacity.***  Access to firm transportation is alsoa significant element of our business strategy. Firm transportation ensures that our equity production has access todownstream markets and allows us to capture incremental profit when pricingdifferentials between physical locations occur. Firm transportation agreements generally require the payment of fixedmonthly fees regardless of the quantity of gas that flows under a particularagreement.  These agreements are notreflected on our Consolidated Balance Sheet.

 

29

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At June 30,2005, the fixed fees associated with our existing contracts for firmtransportation capacity during 2005 will average approximately $0.16 perMcf.  The associated contract periodsrange from one month to twelve years. Under firm transportation contracts, we are required to pay the feesassociated with these contracts whether or not the transportation is used.

 

***Firm Storage Capacity Agreements*.**  Wecustomarily store gas in underground storage facilities to ensure an adequatesupply for long-term sales contracts and to capture seasonal pricedifferentials.  As of June 30, 2005,we had contracts in place for approximately 17.6 Bcf of storage capacity atvarious third-party facilities.  Firmstorage agreements generally require the payment of fixed monthly feesregardless of the quantity of gas that is in storage under a particularagreement.  Of the total storage capacity under contract,approximately 7.0 Bcf is under contract to our Canadian subsidiary, WGR Canada, Inc.,and Western guarantees the subsidiary’s performance under these contracts.  This subsidiary is wholly owned by us andfully consolidated in our financial statements.

 

The fees associated withthese contracts in 2005 will average $0.59 per Mcf of annual capacity.  The associated contract periods at June 30,2005 had an average term of 34 months. At June 30, 2005, we held gas in our contracted storage facilitiesand in imbalances of approximately 18.8 Bcf at an average cost of $6.05 per Mcf comparedto 14.5 Bcf at an average cost of $5.33 per Mcf at June 30, 2004.  These positions are for storage withdrawalswithin the next 12 months.  At the timewe place product into storage, we contract for the sale of that product,physically or financially, and do not speculate on the future value of the product.  These agreements for storage capacityare not reflected on our Consolidated Balance Sheet.

 

Fromtime to time, we lease NGL storage space at major trading locations tofacilitate the distribution of products. At June 30, 2005, we held NGLs instorage at various third-party facilities of 2,917 MGal, consisting primarilyof propane and ethane, at an average cost of $0.32 per gallon compared to 2,755MGal at an average cost of $0.28 per gallon at June 30, 2004.

 

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

#### ** **

***Revolving Credit Facility. ***The commitment under the revolving creditfacility totals $500 million and matures in June 2009.  At June 30, 2005, $262.0 million wasoutstanding under this facility.  Loansmade under this facility are secured by a pledge of the capital stock of our significantsubsidiaries, and these subsidiaries also guarantee the borrowings under thefacility.

 

Theborrowings under our credit facility bear interest at Eurodollar rates or abase rate, as requested by us, plus an applicable percentage based on our debtto capitalization ratio.  The base rateis the agent’s published prime rate.  Wealso pay a quarterly commitment fee ranging between 0.20% and 0.375%, dependingon our debt to capitalization ratio. This fee is paid on unused amounts of the commitment.  At June 30, 2005, the interest ratepayable on borrowings under this facility was approximately 4.5% per year.  Under the credit facility, we are subject toa number of covenants, including: maintaining a total debt to capitalizationratio of not more than 55% and maintaining a ratio of EBITDA, as defined in thecredit facility, to interest over the last four quarters in excess of 3.0 to1.0.  The credit facility ranks equallywith borrowings under our master shelf agreement with The Prudential InsuranceCompany.  This facility has been ratedBa1 by Moody’s and BB+ by S&P.

 

***Master Shelf Agreement. ***Amountsoutstanding under our master shelf agreement at July 31, 2005 are asindicated 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    |               |       |                    |               |                              |                                   |   |

 

Ourborrowings under our master shelf agreement are secured by a pledge of thecapital stock of our significant subsidiaries. These subsidiaries also guarantee the borrowings under thisfacility.  All of the borrowings underour master shelf agreement can be prepaid prior to their final maturity bypaying a yield-maintenance fee.  Underour master shelf agreement, we are subject to a number of covenants, including:maintaining a total debt to capitalization ratio of not more 

 

30

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than55% and maintaining 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.

 

InJuly 2005, we funded a scheduled payment of $10.0 million on these noteswith a borrowing under our revolving credit facility.

 

***Upstream Operations***

 

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

 

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

 
| ** **             | ** ** | **As of June 30, 2005** | ** ** | ** **                  | ** ** |
|------------------------|------------|------------------------------|------------|-----------------------------|------------|
| **Production Area**    | ** ** | **Gross Acres  Under Lease** | ** ** | **Net Acres   Under Lease** | ** ** | **Gross  Productive   Gas Wells** | ** ** | **Net   Productive   Gas Wells** | ** ** | **Net Production  S****old  (Mmcfe per day)******* | ** ** |
| Powder River Basin     |       | 1,041,000                    |       | 531,000                     |       | 4,603 |   | 2,179 |   | 113 |   |
| Jonah/Pinedale Field   |       | 178,000                      |       | 45,000                      |       | 254 |   | 29 |   | 36 |   |
| San Juan Basin         |       | 27,000                       |       | 26,000                      |       | 147 |   | 127 |   | 10 |   |
| Sand Wash Basin        |       | 141,000                      |       | 134,000                     |       | 19 |   | 19 |   | 5 |   |
| Denver-Julesburg Basin |       | 393,000                      |       | 339,000                     |       | 9 |   | 9 |   | — |   |
| Other                  |       | 592,000                      |       | 516,000                     |       | 13 |   | 3 |   | 1 |   |
| Total                  |       | 2,372,000                    |       | 1,591,000                   |       | 5,045 |   | 2,366 |   | 165 |   |

 

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* Average for the sixmonths ended June 30, 2005.

 

***Drilling Results.* **The following table sets forth the numberof wells we drilled during the six months ended June 30, 2005 and 2004 ineach of our major producing areas.  Thisinformation should not be considered indicative of future performance, norshould it be assumed that there is necessarily any correlation between thenumber of productive wells drilled, quantities of reserves found or economicvalue.

 

| ** **             | ** ** | ** **               | ** ** | **Six Months Ended June 30,** | ** ** |
|------------------------|------------|--------------------------|------------|------------------------------------|------------|
| ** **             | ** ** | ** **               | ** ** | **2005**                           | ** ** | **2004** | ** ** |
| **Productive Area**    | ** ** | **Type of Well Drilled** | ** ** | **Gross**                          | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Powder River Basin CBM |       | Productive               |       | 365                                |       | 181 |   | 309 |   | 159 |   |
|                   |       |                     |       |                               |       |   |   |   |   |   |   |
| Jonah/Pinedale Field   |       | Productive               |       | 44                                 |       | 4 |   | 22 |   | 2 |   |
|                   |       | Dry exploratory          |       | 1                                  |       | 0 |   | 0 |   | 0 |   |
|                   |       |                     |       |                               |       |   |   |   |   |   |   |
| San Juan Basin         |       | Productive               |       | 27                                 |       | 25 |   | 0 |   | 0 |   |
|                   |       |                     |       |                               |       |   |   |   |   |   |   |
| Sand Wash Basin        |       | Productive               |       | 0                                  |       | 0 |   | 4 |   | 4 |   |
|                   |       | Dry exploratory          |       | 1                                  |       | 1 |   | 1 |   | 1 |   |
|                   |       |                     |       |                               |       |   |   |   |   |   |   |
| Other                  |       | Exploratory productive   |       | 10                                 |       | 4 |   | 0 |   | 0 |   |

 

***Powder River Basin Coal BedMethane. ***Wecontinue to develop our Powder River Basin CBM reserves and expand theassociated gathering system in northeast Wyoming.  Our net production sold from the Powder RiverBasin CBM averaged 113 MMcf per day in the first six months of 2005.

 

Ourproduction from the Big George coal continues to increase and was 108 MMcf perday gross at June 30, 2005, or 45 MMcf per day net, from the All NightCreek Unit, Pleasantville, SG Palo, Bullwhacker, Schoonover and Kingsbury Unitareas.  In the Big George coal, as of July 2005,we had 878 gross wells dewatering and producing gas, 473 gross wells dewateringand 653 gross wells drilled and in various stages of completion and hook-up in preparation for dewateringand production.

 

31

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Drillingin the Powder River Basin is dependent on the receipt of various regulatorypermits, including BLM drilling permits, DEQ water discharge permits, and theWyoming State Engineer’s Office reservoir permits.  Most of our undeveloped prospects from theBig George formation are located in the Powder River drainage area.  Water management techniques utilized by us,and approved by the DEQ on a site-specific basis, have included containment ortreating.  In order to facilitate theprocessing of our water discharge permit applications, on the west side of thebasin, and in advance of the final requirements of the DEQ, we have installedand tested various types of water treatment facilities and are treating thewater produced in some areas of the basin and, with the approval of the DEQ,discharging this water into the Powder River. We believe many of the future developments in the Big George coal willlikely require water treatment facilities. These treating operations have added and will add to the cost ofdevelopment and operations in these areas. We continue to evaluate several options for water treatment and areworking with the governmental agencies to identify effective and cost efficientmethods.

 

 Our 2005 capital budget for the Powder RiverBasin coal bed project is estimated at $81.2 million for the drilling of 850gross wells, of which $56.0 million was spent in the first six months of 2005.  In 2005, in the Big George and related coals,we plan to participate in the drilling of 730 gross wells, or 365 net wells,and in the Wyodak and related coals, we plan to participate in an additional120 gross wells, or 60 net wells.  Anestimated 640 wells of the 850 well program will be on federal leaseholds andrequire drilling permits from the BLM. The remaining 210 well locations are on fee or state leaseholds.  Together with our co-developer, as of July 31,2005, we have drilling permits approved for 557, or 87% of the federal wells plannedfor 2005.  Federal drilling permitapplications for another 389 locations have been submitted to the BLM.  Timely receipt of these permits would allowus to complete our planned 2005 drilling program, and a portion of our 2006drilling program, on federal leaseholds.

 

Approximately300 gross wells in our 2005-drilling program will require permits to treatproduced water.  The remainder of thewells to be drilled in 2005 will require more conventional types of waterdischarge permits, such as reservoir containment or surface discharge.  To date, we, together with our co-developerin this area, have received water discharge permits from the DEQ forapproximately 71% of the wells we plan to drill in 2005.  An additional 293 permit applications havebeen submitted to the DEQ which, when combined with permits received, is morethan enough necessary to complete our 2005 drilling program.  Historically, the DEQ permit process hasrequired approximately 120 to 150 days from initial submittal to final approval.  There is, however, no assurance as to thefuture timing of the receipt of drilling and water discharge permits, thesuccess of our drilling program, or the dewatering time as our developmentprogresses into the western and northern parts of the Powder River Basin.

 

On April 30,2003, the BLM issued the final Record of Decision, or ROD, for the Powder RiverBasin Oil & Gas Environmental Impact Statement, or EIS.  The ROD requires additional surveys for plantand animal species, cultural surveys and noxious weed mitigation prior to theBLM granting a drilling permit.  A numberof cases have been filed by environmental groups against the BLM in Wyomingdisputing the validity of the EIS and ROD. Due to our interests in developing federal leases in the Powder RiverBasin, we are an intervenor defendant in each of the foregoing cases.  In one of these cases filed in the UnitedStates District Court of Montana, the court was asked to address the adequacy of the Montana PowderRiver Basin ROD and whether the BLM should have issued a single EIS for thePowder River Basin.  Under an Order datedMarch 4, 2005, the court found that a single EIS for the Powder RiverBasin is not required under the National Environmental Policy Act, or NEPA. This Order has been subsequentlyappealed.  As these cases proceed,the BLM, in the event of any adverse rulings, may be required to performfurther environmental analysis and, in addition, could be ordered to ceaseissuing drilling permits until it has completed such further analysis.  Consequently, our ability to receive permitsand develop our leases may be delayed or restricted by the outcome of thesecases.

 

On August 10,2004, the Tenth Circuit Court of Appeals issued its decision in PennacoEnergy, Inc. v. United States Department of the Interior.  The court upheld a decision by the InteriorBoard of Land Appeals, or IBLA, that the BLM had not complied with the NEPA inissuing three federal leases to Pennaco Energy, Inc. in the Powder RiverBasin for coalbed methane development. We are not a party to the case, and the IBLA and Tenth Circuit decisionsdo not directly address any federal leases held by us.  In order to resolve the issues raised in thePennaco decision and related issues, the BLM filed for and received publiccomment on two proposed environmental assessments.  After completion of the environmentalassessments, we were advised that the BLM believes the issues raised in thePennaco decision will be resolved.  Wecannot predict what other actions the Department of Interior or third partiesmight take in response to this matter, or how the decision and actions taken bythe BLM in response to the decision may affect the pace of federal leasing orpermitting and development in the Powder River Basin.

 

Acomplaint was filed on January 31, 2005 in the U.S. District Court ofWyoming against the BLM and the Department of Interior.  The complaint alleges that the BLM violatedNEPA “as described in Pennaco Energy, Inc. v. United States 

 

32

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Department of the Interior” becausethe BLM did not consider the effects of CBM development prior to issuing fiveleases, including one issued to us.  On July 12,2005, the plaintiffs amended their complaint by deleting four of the fiveleases included in their January 31, 2005 complaint, including the leasein which we hold an interest. Additionally, the plaintiffs added 45 other leases to their AmendedComplaint, including nine leases in which we hold an interest.  These nine leases cover approximately 5,300gross and 2,650 net acres.  Theplaintiffs have asked the court for a “review of the issuance” of theseleases.  We cannot predict what actions,if any, the Department of the Interior, third parties, or the court might takein response to this case, or how these actions may affect the pace of federaldrilling or permitting and development of the Powder River Basin.

 

***Jonah/Pinedale Fields.***  Our exploration and production assets in theGreen River Basin of southwest Wyoming are located in the Pinedale Anticlineand Jonah Field areas.  During 2005, weexpect to participate in the drilling of 80 gross wells, or approximately ninenet wells, on the Pinedale Anticline.  Ourcapital budget for 2005 in the Pinedale Anticline area provides for expendituresof approximately $47.9 million for drilling costs and production equipment, ofwhich $23.9 million was spent in the first six months of 2005.  Due to drilling and regulatory uncertainties,which are beyond our control, there can be no assurance that we will incur thislevel of capital expenditure during 2005.

 

#### ***MidstreamOperations***

#### ** **

Our midstream operations consist of ourgathering, processing, treating, marketing and transportation operations.  An important element of our long-termbusiness plan is to meet or exceed throughput projections in these areas and tooptimize their profitability.  To achievethis goal, we must continue our efforts to add to natural gas throughput levelsthrough new well connections and through the expansion or acquisition of gatheringor processing systems in those basins in which we currently operate or in newbasins.  We also seek to increase theefficiency of our operations by modernization of equipment and theconsolidation of existing facilities.

 

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

 

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

 

In April 2005,we entered into an agreement to acquire a 200 MMcf per day cryogenic processingfacility for $9.0 million.  We intend tospend an additional $28.5 million to install this facility and expand ourChaney Dell/Westana processing and gathering complex.  We currently expect that this facility will beoperational in the second quarter of 2006.

 

33

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***Principal Gathering and ProcessingFacilities Table.*** The following table provides information concerning our principalgathering, processing and treating facilities at June 30, 2005.

 
| ** **                     | ** ** | **Year**                 | ** ** | **Gas**                      | ** ** | **Gas**                               | ** ** | **Average for the Six Months Ended  June 30, 2005** | ** ** |
|--------------------------------|------------|--------------------------|------------|------------------------------|------------|---------------------------------------|------------|----------------------------------------------------------|------------|
| **Facilities (1)**             | ** ** | **Placed  in   Service** | ** ** | **Gathering  System  Miles** | ** ** | **Throughput  Capacity  (MMcf/D)(2)** | ** ** | **Gas  Throughput  (MMcf/D) (3)**                        | ** ** | **Gas  Production  (MMcf/D)(4)** | ** ** | **NGL  Production  (MGal/D) (4)** | ** ** |
| Texas                          |       |                     |       |                         |       |                                  |       |                                                     |       |   |   |   |   |
| Gomez Treating  (5)            |       | 1971                     |       | 389                          |       | 280                                   |       | 87                                                       |       | 79 |   | — |   |
| Midkiff/Benedum                |       | 1949                     |       | 2,344                        |       | 165                                   |       | 145                                                      |       | 93 |   | 858 |   |
| Mitchell Puckett  Treating (5) |       | 1972                     |       | 126                          |       | 120                                   |       | 36                                                       |       | 22 |   | 1 |   |
| Wyoming                        |       |                     |       |                         |       |                                  |       |                                                     |       |   |   |   |   |
| Coal Bed Methane  Gathering    |       | 1990                     |       | 1,369                        |       | 548                                   |       | 391                                                      |       | 354 |   | — |   |
| Desert Springs  Gathering      |       | 1979                     |       | 65                           |       | 10                                    |       | 6                                                        |       | 5 |   | 21 |   |
| Fort Union Gas  Gathering(12)  |       | 1999                     |       | 167                          |       | 635                                   |       | 484                                                      |       | 484 |   | — |   |
| Granger Complex  (6)(7)(8)     |       | 1987                     |       | 714                          |       | 325                                   |       | 287                                                      |       | 248 |   | 389 |   |
| Granger Straddle  Plant        |       | 2004                     |       | —                       |       | 200                                   |       | 138                                                      |       | — |   | 10 |   |
| Hilight Complex  (6)           |       | 1969                     |       | 658                          |       | 124                                   |       | 17                                                       |       | 12 |   | 61 |   |
| Kitty/Amos Draw  (6)           |       | 1969                     |       | 321                          |       | 17                                    |       | 5                                                        |       | 3 |   | 24 |   |
| Newcastle (6)                  |       | 1981                     |       | 146                          |       | 5                                     |       | 3                                                        |       | 2 |   | 21 |   |
| Patrick  Draw(6) (9)      |       | 1997                     |       | 284                          |       | 150                                   |       | 28                                                       |       | 24 |   | 61 |   |
| Red Desert (6)                 |       | 1979                     |       | 127                          |       | 42                                    |       | 18                                                       |       | 31 |   | 57 |   |
| Rendezvous (10)                |       | 2001                     |       | 238                          |       | 325                                   |       | 331                                                      |       | 331 |   | — |   |
| Reno Junction  (7)             |       | 1991                     |       | —                       |       | —                                |       | —                                                   |       | — |   | 116 |   |
| Table Rock  Gathering          |       | 1979                     |       | 100                          |       | 20                                    |       | 12                                                       |       | 12 |   | — |   |
| Wamsutter  Gathering (11)      |       | 1979                     |       | 243                          |       | 50                                    |       | 48                                                       |       | 43 |   | 26 |   |
| Wind River  Gathering          |       | 1979                     |       | 137                          |       | 80                                    |       | 48                                                       |       | 47 |   | — |   |
| Oklahoma                       |       |                     |       |                         |       |                                  |       |                                                     |       |   |   |   |   |
| Chaney  Dell/Westana           |       | 1966                     |       | 3,359                        |       | 175                                   |       | 197                                                      |       | 175 |   | 308 |   |
| New Mexico                     |       |                     |       |                         |       |                                  |       |                                                     |       |   |   |   |   |
| San Juan River  (5)            |       | 1955                     |       | 277                          |       | 60                                    |       | 26                                                       |       | 21 |   | 37 |   |
| Utah                           |       |                     |       |                         |       |                                  |       |                                                     |       |   |   |   |   |
| Four Corners  Gathering        |       | 1988                     |       | 104                          |       | 15                                    |       | 3                                                        |       | 2 |   | 15 |   |
| Yellow Creek  (9) (13)    |       | 1985                     |       | —                       |       | —                                |       | —                                                   |       | — |   | 73 |   |
| Total                          |       |                     |       | 11,168                       |       | 3,346                                 |       | 2,310                                                    |       | 1,988 |   | 2,078 |   |

 

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| (1)  | Our interest in  all facilities is 100% except for Midkiff/Benedum (73%); Newcastle (50%);  Fort Union (13%) and Rendezvous (50%). We operate all facilities, and all  data include our interests and the interests of other joint interest owners  and producers of gas volumes dedicated to the facility. Unless otherwise  indicated, all facilities shown in the table are gathering, processing or  treating facilities. |
|------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (2)  | Gas throughput  capacity is as of June 30, 2005 and represents capacity in accordance  with design specifications unless other constraints exist, including  permitting or field compression limits.                                                                                                                                                                                                                     |
| (3)  | Aggregate  natural gas volumes delivered into our gathering systems.                                                                                                                                                                                                                                                                                                                                                          |
| (4)  | Volumes of gas  and NGLs are allocated to a facility when a well is connected to that  facility; volumes exclude NGLs fractionated for third parties.                                                                                                                                                                                                                                                                         |
| (5)  | Sour gas  facility (capable of processing or treating gas containing hydrogen sulfide  and/or carbon dioxide).                                                                                                                                                                                                                                                                                                                |
| (6)  | Processing  facility that includes fractionation (capable of fractionating raw NGLs into  end-use products).                                                                                                                                                                                                                                                                                                                  |
| (7)  | NGL production  includes conversion of third-party feedstock to iso-butane.                                                                                                                                                                                                                                                                                                                                                   |
| (8)  | The Granger  Complex includes the Lincoln Road facility. The volume information for this  facility is reported with the volume information for Granger.                                                                                                                                                                                                                                                                       |
| (9)  | This facility  was acquired in a transaction, which was completed on February 1, 2005.                                                                                                                                                                                                                                                                                                                                   |
| (10) | The majority of  the gas gathered by the Rendezvous gas gathering system is delivered to our  Granger facility and is included with the volume information reported for  Granger.                                                                                                                                                                                                                                             |
| (11) | A portion of the  gas gathered by the Wamsutter gas gathering system is delivered to our Red  Desert facility and is included with the volume information reported for Red  Desert.                                                                                                                                                                                                                                           |
| (12) | A portion of the  gas gathered by Fort Union is also reported under Coal Bed Methane Gathering.                                                                                                                                                                                                                                                                                                                               |
| (13) | NGL fractionation  facility that receives product from third parties via liquids pipeline and  truck.                                                                                                                                                                                                                                                                                                                         |

 

34

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

##### *** ***

##### ***We own and operate MIGC, Inc.,an interstate pipeline located in the Powder River Basin, and MGTC, Inc.,an intrastate pipeline located in northeast Wyoming.  MIGC charges a Federal Energy RegulatoryCommission, or FERC, approved tariff and is connected to pipelines owned byColorado Interstate Gas Company, Williston Basin Interstate Pipeline Company,Kinder Morgan Interstate Pipeline Co., Wyoming Interstate Company, Ltd. andMGTC.  MIGC earns fees on a monthly basisfrom firm capacity contracts under which the shipper pays for transportcapacity whether or not the capacity is used and from interruptible contractswhere a fee is charged based upon volumes received into the pipeline.  Contracts with third parties for capacity onMIGC range in duration from one month to approximately five years, and the feescharged averaged $0.35 per Mcf in the first six months of 2005.  MGTC, a public utility, providestransportation and gas sales to various cities in Wyoming at rates that aresubject to the approval of the Wyoming Public Service Commission.***

##### *** ***

Thefollowing table provides information concerning our principal transportationassets at June 30, 2005.

 
| ** **                        | ** ** | ** **                      | ** ** | ** **                | ** ** | **Average for the Six Months Ended  June 30, 2005** | ** ** |
|-----------------------------------|------------|---------------------------------|------------|---------------------------|------------|----------------------------------------------------------|------------|
| **Transportation Facilities (1)** | ** ** | **Year Placed In Service** | ** ** | **Transportation  Miles** | ** ** | **Pipeline Capacity (MMcf/D) (2)**                       | ** ** | **Gas Throughput (MMcf/D) (3)** | ** ** |
| MIGC                              |       | 1970                            |       | 263                       |       | 130                                                      |       | 138 |   |
| MGTC                              |       | 1963                            |       | 251                       |       | 18                                                       |       | 10 |   |
| Total                             |       |                            |       | 514                       |       | 148                                                      |       | 148 |   |

 

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

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

(3)                      Aggregatevolumes transported by a pipeline.

 

***Marketing***

 

***Gas*.*   ***We market gasproduced at our wells and at our plants and gas purchased from third parties toend-users, local distribution companies, or LDCs, pipelines and other marketingcompanies throughout the United States and Canada.  In addition to our offices in Denver, we havemarketing offices in Houston, Texas and Calgary, Alberta.  Third-party sales, firm transportationcapacity on interstate pipelines and our gas storage positions, combined withthe stable supply of gas from our facilities and production, enable us torespond quickly to changing market conditions and to take advantage of seasonalprice variations and peak demand periods. One of the primary goals of our gas marketing operations continues to bethe preservation and enhancement of the value received for our equity volumesof natural gas.  This goal is achievedthrough the use of hedges on the production of our equity natural gas andthrough the use of firm transportation capacity.

 

***NGLs*.* ***We market NGLs,or ethane, propane, iso-butane, normal butane, natural gasoline and condensate,produced at our plants and purchased from third parties, in the Rocky Mountain,Mid-Continent and Southwestern regions of the United States.  A majority of our production of NGLs moves tothe Gulf Coast area, which is the largest NGL market in the United States.  Through the development of end-use marketsand distribution capabilities, we seek to ensure that products from our plantsmove on a reliable basis, avoiding curtailment of production. Consumers of NGLsare primarily the petrochemical industry, the petroleum refining industry andthe retail and industrial fuel markets. As an example, the petrochemical industry uses ethane, propane, normalbutane and natural gasoline as feedstocks in the production of ethylene, whichis used in the production of various plastics products.  Further, consumers use propane for homeheating, transportation and agricultural applications.  Price, seasonality and the economy primarilyaffect the demand for NGLs.

 

35

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

 

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

 

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

 

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

 

Weenter into futures transactions on the New York Mercantile Exchange, or NYMEX,and OTC swaps and options with various counterparties, consisting primarily ofinvestment banks, financial institutions and other natural gas companies.  We conduct credit reviews of all of our OTCcounterparties and have agreements with many of these parties that containcollateral requirements.  We generallyuse standardized swap agreements that allow for offset of positive and negativeOTC exposures with the same counterparty. OTC exposure is marked-to-market daily for the credit reviewprocess.  Our exposure to OTC credit riskis reduced by our ability to require a margin deposit from our counterpartiesbased upon the mark-to-market value of their net exposure.  We are also subject to margin depositrequirements under these same agreements and under margin deposit requirementsfor our NYMEX transactions.  At June 30,2005, we had $15.1 million of margin deposits outstanding.

 

Wecontinually monitor and review the credit exposure to our marketingcounterparties.  In recent months theprices of natural gas and NGLs, and therefore our credit exposures, haveincreased significantly.  In order tominimize our credit exposures, we have utilized existing netting agreements toreduce our net credit exposure, established new netting agreements withadditional customers, terminated several long-term marketing obligations,negotiated accelerated payment terms with several customers, and increased theamount of credit which we make available to substantial companies which meet ourcredit 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.

 

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

 

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

 

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

 

36

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***Hedge Positions.* ** The hedge contracts are designated andaccounted for as cash flow hedges.  Assuch, gains and losses related to the effective portions of the changes in thefair value of the derivatives are recorded in Accumulated other comprehensiveincome, a component of Stockholders’ equity. Realized gains or losses on these cash flow hedges are recognized in theConsolidated Statement of Operations through Sale of gas or Sale of natural gasliquids when the hedged transactions occur.

 

Toqualify as cash flow hedges, the hedge instruments must be designated as cashflow hedges and changes in their fair value must be highly effective atoffsetting changes in the price of the forecasted transaction being hedged sothat our exposure to the risk of commodity price changes is reduced.  To meet this requirement, we hedge the priceof the commodity and, if applicable, the basis between that derivative’scontract delivery location and the cash market location used for the actualsale of the product.  This structureattains a high level of effectiveness, ensuring that a change in the price ofthe forecasted transaction will result in an equal and opposite change in theprice of the derivative instrument hedging the transaction. We utilize crudeoil as a surrogate hedge for natural gasoline and condensate.  Our hedges are tested for effectiveness atinception and on a quarterly basis thereafter. We use regression analysis based on a five-year period of time for thistest.  Gains or losses from theineffective portions of changes in the fair value of cash flow hedges arerecognized currently in earnings through Price risk management activities.  During the first six months of 2005, werecognized a loss of $125,000 from the ineffective portions of our hedges.

 

***Earnings Sensitivity.***  Historically, the non-cash mark-to-marketvaluation of the gas storage and transportation contracts which were consideredto be derivatives effectively offset non-cash mark-to-market changes to theforward derivative contract to sell our stored or transported natural gas.  After the adjustments to correct the prioraccounting for these contracts as derivatives, the non-cash mark-to-market ofthe future sale derivative contract on the sale of gas will fluctuate throughearnings with changes in market prices and will not be offset by acorresponding mark to market on the gas storage and transportationcontracts.  For example, at June 30, 2005, we heldgas in our contracted storage facilities and in imbalances of approximately18.8 Bcf.  This inventoried gas was soldforward with derivatives.  Based on a$1.00 increase in the forward price of gas in the anticipated month ofwithdrawal, the change in the non-cash mark-to-market value of thesederivatives will reduce pre-tax earnings by $18.8 million and a $1.00 decreasein the forward price of gas in the anticipated month of withdrawal willincrease pre-tax earnings by $18.8 million. As the stored or transported natural gas is sold and the futuresale derivatives are settled, we will realize the benefit of the storage andtransportation transactions through earnings.

 

***Outstanding Equity Hedge Positions and theAssociated Basis for 2005 and 2006.***  The following table details our hedgepositions as of June 30, 2005.  Inorder to determine the hedged price to the particular operating region, deductthe basis differential from the settle price. The prices for NGLs do not include the cost of the hedges ofapproximately $312,000 as of June 30, 2005.  There is no associated cost for the naturalgas hedges.

 
| **Product**                         | ** ** | **Year** | ** ** | **Quantity  and Settle Price**                                                                                                   | ** ** | **Hedge of  Basis Differential**                                                                                                                                                                                                                                            |
|-------------------------------------|------------|----------|------------|----------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| Natural gas                         |       | 2005     |       | 80,000 MMBtu per day  with an average minimum price of $4.75 per MMBtu and an average maximum price  of $8.88 per MMBtu.         |       | Mid-Continent – 60,000  MMBtu per day with an average basis price of $0.42 per MMBtu.  Permian – 5,000 MMBtu per day with an average basis price of $0.48 per MMBtu.  Rocky Mountain – 15,000 MMBtu per day with an average basis price of $0.72  per MMBtu. |
|                                |       |     |       |                                                                                                                             |       |                                                                                                                                                                                                                                                                        |
|                                |       | 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.        |       | Mid-Continent – 40,000  MMBtu per day with an average basis price of $0.55 per MMBtu.                                                                                                                                                                                  |
|                                |       |     |       |                                                                                                                             |       |                                                                                                                                                                                                                                                                        |
| Crude, Condensate, Natural Gasoline |       | 2005     |       | 50,000 Barrels per  month with an average minimum price of $31.00 per barrel and an average  maximum price of $48.01 per barrel. |       | Not Applicable                                                                                                                                                                                                                                                              |
|                                |       |     |       |                                                                                                                             |       |                                                                                                                                                                                                                                                                        |
|                                |       | 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                                                                                                                                                                                                                                                              |
|                                |       |     |       |                                                                                                                             |       |                                                                                                                                                                                                                                                                        |
| Propane                             |       | 2005     |       | 75,000 Barrels per  month with an average minimum price of $0.52 per gallon and an average  maximum price of $0.88 per gallon.   |       | Not Applicable                                                                                                                                                                                                                                                              |
|                                |       |     |       |                                                                                                                             |       |                                                                                                                                                                                                                                                                        |
| Ethane                              |       | 2005     |       | 75,000 Barrels per  month. Floor at $0.38 per gallon.                                                                            |       | Not Applicable                                                                                                                                                                                                                                                              |

 

37

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Accountbalances related to hedging transactions (designated as cash flow hedges underSFAS 133) at June 30, 2005 were $2.9 million in Current assets from pricerisk management activities, $8.4 million in Current liabilities from price riskmanagement activities, $1.0 million in Liabilities from price risk managementactivities, ($2.3) million in Deferred income taxes payable, net, and a $4.0million after-tax unrealized loss in Accumulated other comprehensive income, acomponent of Stockholders’ equity. Approximately $2.5 million of the unrealized loss in Accumulated othercomprehensive income will be reclassified to earnings in the remainder of 2005.

 

***Summary of Derivative Positions.***  A summary of the change in our derivativeposition from December 31, 2004 to June 30, 2005 is as follows(dollars in thousands):

 
| Fair value of  contracts outstanding at December 31, 2004 (restated) |   | $      | 15,640  |   |
|---------------------------------------------------------------------------|--------|--------|---------|--------|
| Decrease in value due to change in price                                  |   | (7,767 | )       |
| Decrease in value due to new contracts entered into  during the period    |   | (9,552 | )       |
| Gains realized during the period from existing and  new contracts         |   | (8,640 | )       |
| Changes in fair value attributable to changes in  valuation techniques    |   | — |    |
| Fair value of contracts outstanding at June 30,  2005 (restated)     |   | $      | (10,319 | )      |

 

Asummary of our outstanding derivative positions at June 30, 2005 is asfollows (dollars in thousands):

 
| ** **                       | ** ** | **Fair Value of Contracts at June 30, 2005 (restated)** | ** ** |
|----------------------------------|------------|--------------------------------------------------------------|------------|
| **Source of Fair Value**         | ** ** | **Total  Fair Value**                                        | ** ** | **Maturing   In 2005** | ** ** | **Maturing In   2006-2007** | ** ** | **Maturing In   2008-2009** | ** ** | **Maturing  Thereafter** | ** ** |
| Exchange published prices        |       | $                                                            | (4,867     | ) | $ | (810 | ) | $ | (4,057 | ) | — |   | — |   |
| Other actively quoted prices (1) |       | 3,619                                                        |       | 3,348 |   | 247 |   | $ | 24 |   | — |   |
| Other valuation methods (2)      |       | (9,071                                                       | )          | (6,411 | ) | (2,660 | ) | — |   | — |   |
| Total fair value                 |       | $                                                            | (10,319    | ) | $ | (3,873 | ) | $ | (6,470 | ) | $ | 24 |   | — |   |

 

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

 

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

 

***Foreign Currency Derivative MarketRisk***.  As a normal part ofour business, we enter into physical gas transactions which are payable inCanadian dollars.  We enter into forwardpurchases and sales of Canadian dollars from time to time to fix the cost ofour future Canadian dollar denominated natural gas purchase, sale, storage, andtransportation obligations.  This is doneto protect marketing margins from adverse changes in the United States andCanadian dollar exchange rate between the time the commitment for the paymentobligation is made and the actual payment date of such obligation.  As of June 30, 2005, we had sold forwardcontracts for  $33.0 million in Canadiandollars in exchange for $27.0 million in United States dollars, and the fairmarket value of these contracts was a gain of $36,000 in United States dollars.

 

38

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**ITEM4.  CONTROLS AND PROCEDURES**

 

**Evaluation of Disclosure Controls andProcedures.**

 

The Company’s management evaluated,with the participation of the Chief Executive Officer and Chief FinancialOfficer, the effectiveness of the Company’s disclosure controls and procedures,as such term is defined under Rule 13a-15(e) of the Securities andExchange Act of 1934, as of the end of the period covered by this QuarterlyReport on Form 10-Q/A. Based on this evaluation, the Chief ExecutiveOfficer and Chief Financial Officer have concluded that because of the materialweakness in internal control over financial reporting relating to thedetermination and periodic review of whether its gas storage and transportationcontracts meet the definition of a derivative under generally acceptedaccounting principles, which was previously identified in “Management’s Reporton Internal Control over Financial Reporting (as restated)” included in Item 8of our Annual Report on Form 10-K/A for the year ended December 31,2004 (“2004 Form 10-K/A”) had not yet been remediated, our disclosurecontrols and procedures were ineffective as of June 30, 2005.  Notwithstanding this material weakness, theCompany’s management believes that the consolidated financial condition,results of operations and cash flows are fairly presented in this Form 10-Q/A.

 

**RemediationEfforts to Address This Material Weakness.**

 

In the fourthquarter of 2005, we implemented controls to ensure that all contracts accountedfor as derivatives are reviewed as to their terms and the markets on which theyare traded to reaffirm that each contract meets the definition of aderivative.  This control will beperformed on a monthly basis.

 

**Changes in Internal Control Over FinancialReporting.**

 

There were nomaterial changes to internal controls over financial reporting during the firstquarter ended June 30, 2005, that have materially affected, are reasonablylikely to materially affect, the Company’s internal control over financialreporting. Management continues to work on its remediation plan to address thematerial weakness relating to the accounting for gas transportation and storagecontracts identified in our 2004 Form 10-K/A.

 

**PART II- OTHER INFORMATION**

 

**ITEM 1.    LEGAL PROCEEDINGS**

 

Referenceis made to “Notes to Consolidated Financial Statements (Unaudited)  – Legal Proceedings,” in Item 1 of this Form 10-Q/Aand incorporated by reference in this Item 1.

 

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

 

Thefollowing matters were voted on at our Annual Meeting of Stockholders held on May 6,2005:

 

BrionG. Wise, Richard B. Robinson and Peter A. Dea were elected as class onedirectors to serve until their terms expire in 2008 and until their successorshave been elected.  The results of theelection were as follows.

 

| ** **          | ** ** | **Votes For** | ** ** | **Votes Withheld** | ** ** |
|---------------------|------------|---------------|------------|--------------------|------------|
| Peter A. Dea        |       | 67,569,057    |       | 2,753,169          |       |
| Richard B. Robinson |       | 66,497,342    |       | 3,824,884          |       |
| Brion G. Wise       |       | 66,682,697    |       | 3,639,529          |       |

 

 

Ourother directors whose terms did not expire on the date of the Annual Meeting,James A. Senty, Walter L. Stonehocker, Joseph E. Reid, Bill M. Sanderson, WardSauvage, and, Dean Phillips continued in office.  Mr. Sauvage subsequently resigned as amember of our board of directors on July 15, 2005 due to health reasons.

 

Our2005 Stock Incentive Plan, which provides for the issuance of options topurchase 2.5 million shares of common stock and 1.5 million shares ofrestricted common stock, was approved as follows:

 
| ** **                | ** ** | **Votes For** | ** ** | **Votes Against** | ** ** | **Abstentions** | ** ** | **Broker Non-votes** | ** ** |
|---------------------------|------------|---------------|------------|-------------------|------------|-----------------|------------|----------------------|------------|
| 2005 Stock Incentive Plan |       | 54,960,656    |       | 6,358,752         |       | 116,102         |       | 8,886,716            |       |

 

39

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**ITEM 6.      EXHIBITS**

 
| **Exhibit** | ** ** | ** **                                                                                                                                                                                                                                                                |
|-------------|------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| **Number**  | ** ** | **Description**                                                                                                                                                                                                                                                           |
|        |       |                                                                                                                                                                                                                                                                      |
| 3.1         |       | Certificate  of Incorporation of Western Gas Resources, Inc. (previously filed as  Exhibit 3.1 to our Registration Statement on Form S-1, Registration  No. 33-31604 and incorporated herein by reference).                                           |
|        |       |                                                                                                                                                                                                                                                                      |
| 3.2         |       | Certificate  of Amendment to the Certificate of Incorporation of Western Gas  Resources, Inc. (previously filed as Exhibit 3.2 to our  Registration Statement on Form S-1, Registration No. 33-31604 and  incorporated herein by reference).          |
|        |       |                                                                                                                                                                                                                                                                      |
| 3.3         |       | Certificate  of Designation, Preferences and Rights of Series A Junior Participating  Preferred Stock (previously filed as part of Exhibit 1 to our  Form 8-A filed on March 30, 2001 and incorporated herein by  reference).                         |
|        |       |                                                                                                                                                                                                                                                                      |
| 3.4         |       | Amended  and Restated Bylaws of Western Gas Resources, Inc. adopted by the Board  of Directors on May 7, 2004 (previously filed as Exhibit 99.1 to  our Current Report on Form 8-K filed on May 11, 2004 and  incorporated herein by reference). |
|        |       |                                                                                                                                                                                                                                                                      |
| 10.1        |       | Western Gas  Resources, Inc. 2005 Stock Incentive Plan (previously filed as  Exhibit 4.7 to our Registration Statement on Form S-8 filed on  May 31, 2005 and incorporated herein by reference).*                                                     |
|        |       |                                                                                                                                                                                                                                                                      |
| 10.2        |       | Amendment to  Employment Agreement of Peter A. Dea (previously filed as Exhibit 10.1  to our Current Report on Form 8-K filed on May 23, 2005 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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|   |   | * Management  contract or compensating plan or arrangement. |
|--------|--------|-------------------------------------------------------------|

 

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SIGNATURES

 

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

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

 

41

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INDEX TO EXHIBITS

 
| **Exhibit** | ** ** | ** **                                                                                                                                                                                                                                                                |
|-------------|------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| **Number**  | ** ** | **Description**                                                                                                                                                                                                                                                           |
|        |       |                                                                                                                                                                                                                                                                      |
| 3.1         |       | Certificate  of Incorporation of Western Gas Resources, Inc. (previously filed as  Exhibit 3.1 to our Registration Statement on Form S-1, Registration  No. 33-31604 and incorporated herein by reference).                                           |
|        |       |                                                                                                                                                                                                                                                                      |
| 3.2         |       | Certificate  of Amendment to the Certificate of Incorporation of Western Gas  Resources, Inc. (previously filed as Exhibit 3.2 to our  Registration Statement on Form S-1, Registration No. 33-31604 and  incorporated herein by reference).          |
|        |       |                                                                                                                                                                                                                                                                      |
| 3.3         |       | Certificate  of Designation, Preferences and Rights of Series A Junior Participating  Preferred Stock (previously filed as part of Exhibit 1 to our  Form 8-A filed on March 30, 2001 and incorporated herein by  reference).                         |
|        |       |                                                                                                                                                                                                                                                                      |
| 3.4         |       | Amended  and Restated Bylaws of Western Gas Resources, Inc. adopted by the Board  of Directors on May 7, 2004 (previously filed as Exhibit 99.1 to  our Current Report on Form 8-K filed on May 11, 2004 and  incorporated herein by reference). |
|        |       |                                                                                                                                                                                                                                                                      |
| 10.1        |       | Western Gas  Resources, Inc. 2005 Stock Incentive Plan (previously filed as  Exhibit 4.7 to our Registration Statement on Form S-8 filed on  May 31, 2005 and incorporated herein by reference).*                                                     |
|        |       |                                                                                                                                                                                                                                                                      |
| 10.2        |       | Amendment to  Employment Agreement of Peter A. Dea (previously filed as Exhibit 10.1  to our Current Report on Form 8-K filed on May 23, 2005 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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|   |   | * Management  contract or compensating plan or arrangement. |
|--------|--------|-------------------------------------------------------------|

 

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