**SECURITIES AND EXCHANGECOMMISSION**

**Washington, D.C. 20549**

 

### **FORM 10-Q**

### ** **

**(MarkOne)**

 
| **ý** | **QUARTERLY REPORT PURSUANT TO SECTION 13 OR  15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**                                                                                                                                                 |
|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| ** ** | ** **                                                                                                                                                                                                                                             |
| ** ** | **FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 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 o  No ý

 

Indicate by check markwhether the registrant is an accelerated filer (as defined in Rule 12b-2of the Exchange Act).  Yes  ý  Noo

 

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

 

As of December 12,2005, there were 75,326,025 shares of the registrant’s Common Stock, par value$0.10, outstanding.

 

 

----

 

**Western Gas Resources, Inc.**

**Form 10-Q**

**Table of Contents**

 
| PART I - Financial Information |                                                                                                        |
|-------------------------------------|-------------------------------------------------------------------------------------------------------------|
|                                |                                                                                                        |   |
| Item 1.                             | Financial Statements                                                                                        |   |
|                                |                                                                                                        |   |
|                                | Consolidated Balance Sheet - September 30,  2005 and December 31, 2004                            |   |
|                                |                                                                                                        |   |
|                                | Consolidated Statement of  Cash Flows - Nine Months Ended September 30, 2005 and 2004                  |   |
|                                |                                                                                                        |   |
|                                | Consolidated Statement of  Operations – Three and Nine Months Ended September 30, 2005 and 2004   |   |
|                                |                                                                                                        |   |
|                                | Consolidated Statement of  Changes in Stockholders’ Equity - Nine Months Ended September 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 6.                             | Exhibits                                                                                                    |   |
|                                |                                                                                                        |   |
| Signatures                          |                                                                                                        |   |

 

2

----

 

**PART I- FINANCIAL INFORMATION**

 

**ITEM 1.**                                                     FINANCIAL STATEMENTS

 

WESTERN GAS RESOURCES, INC.

CONSOLIDATED BALANCE SHEET

(Unaudited)

(Dollars in thousands, except share data)

 
| ** **                                                                                                           | ** ** | **September 30,** | ** ** | **December 31,** | ** ** |
|----------------------------------------------------------------------------------------------------------------------|------------|------------------------|------------|-----------------------|------------|
| ** **                                                                                                           | ** ** | **2005**               | ** ** | **2004**              | ** ** |
| ** **                                                                                                           | ** ** | ** **             | ** ** | **Restated**          | ** ** |
| ASSETS                                                                                                               | ** ** | ** **             | ** ** | ** **            | ** ** |
| Current assets:                                                                                                      |       |                   |       |                  |       |
| Cash and cash equivalents                                                                                            |       | $                      | 19,533     |                  | $          | 390 |   |
| Trade accounts receivable, net                                                                                       |       | 445,747                |       | 385,811               |       |
| Margin deposits                                                                                                      |       | 110,723                |       | 7,939                 |       |
| Product inventory                                                                                                    |       | 129,886                |       | 94,604                |       |
| Assets from price risk management activities                                                                         |       | 36,011                 |       | 19,893                |       |
| Deferred income taxes                                                                                                |       | 48,735                 |       | —                |       |
| Other                                                                                                                |       | 4,906                  |       | 12,494                |       |
| Total current assets                                                                                                 |       | 795,541                |       | 521,131               |       |
|                                                                                                                 |       |                   |       |                  |       |
| Property and equipment:                                                                                              |       |                   |       |                  |       |
| Gas gathering, processing and transportation                                                                         |       | 1,241,221              |       | 1,150,904             |       |
| Oil and gas properties and equipment (successful  efforts method)                                                    |       | 593,859                |       | 495,314               |       |
| Construction in progress                                                                                             |       | 255,803                |       | 150,273               |       |
|                                                                                                                 |       | 2,090,883              |       | 1,796,491             |       |
| Less: Accumulated depreciation, depletion and  amortization                                                          |       | (650,926               | )          | (570,582              | )          |
|                                                                                                                 |       |                   |       |                  |       |
| Total property and equipment, net                                                                                    |       | 1,439,957              |       | 1,225,909             |       |
|                                                                                                                 |       |                   |       |                  |       |
| Other assets:                                                                                                        |       |                   |       |                  |       |
| Gas purchase contracts (net of accumulated  amortization of $42,093 and $40,652, respectively)                       |       | 32,557                 |       | 27,704                |       |
| Assets from price risk management activities                                                                         |       | 4,438                  |       | 249                   |       |
| Equity investments                                                                                                   |       | 40,231                 |       | 35,729                |       |
| Other                                                                                                                |       | 25,192                 |       | 26,676                |       |
|                                                                                                                 |       |                   |       |                  |       |
| Total other assets                                                                                                   |       | 102,418                |       | 90,358                |       |
|                                                                                                                 |       |                   |       |                  |       |
| TOTAL ASSETS                                                                                                         |       | $                      | 2,337,916  |                  | $          | 1,837,398 |   |
|                                                                                                                 |       |                   |       |                  |       |
| LIABILITIES AND STOCKHOLDERS’ EQUITY                                                                            |       |                   |       |                  |       |
| Current liabilities:                                                                                                 |       |                   |       |                  |       |
| Accounts payable                                                                                                     |       | $                      | 483,161    |                  | $          | 400,672 |   |
| Accrued expenses                                                                                                     |       | 83,926                 |       | 60,472                |       |
| Liabilities from price risk management activities                                                                    |       | 171,087                |       | 4,321                 |       |
| Deferred income taxes                                                                                                |       | —                 |       | 5,618                 |       |
| Dividends payable                                                                                                    |       | 3,773                  |       | 3,704                 |       |
| Total current liabilities                                                                                            |       | 741,947                |       | 474,787               |       |
| Long-term debt                                                                                                       |       | 524,500                |       | 382,000               |       |
| Liabilities from price risk management activities                                                                    |       | 8,304                  |       | 180                   |       |
| Other long-term liabilities                                                                                          |       | 60,941                 |       | 51,827                |       |
| Deferred income taxes payable, net                                                                                   |       | 282,956                |       | 243,835               |       |
|                                                                                                                 |       |                   |       |                  |       |
| Total liabilities                                                                                                    |       | 1,618,648              |       | 1,152,629             |       |
|                                                                                                                 |       |                   |       |                  |       |
| Stockholders’ equity:                                                                                           |       |                   |       |                  |       |
| Common stock, par value $0.10; 100,000,000 shares  authorized; 75,135,201 and 74,078,733 shares issued, respectively |       | 7,535                  |       | 7,430                 |       |
| Treasury stock, at cost; 50,032 common shares in  treasury                                                           |       | (788                   | )          | (788                  | )          |
| Unearned compensation                                                                                                |       | (10,207                | )          | —                |       |
| Additional paid-in capital                                                                                           |       | 419,237                |       | 392,437               |       |
| Retained earnings                                                                                                    |       | 338,099                |       | 281,428               |       |
| Accumulated other comprehensive (loss) income                                                                        |       | (34,608                | )          | 4,262                 |       |
|                                                                                                                 |       |                   |       |                  |       |
| Total stockholders’ equity                                                                                      |       | 719,268                |       | 684,769               |       |
|                                                                                                                 |       |                   |       |                  |       |
| TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY                                                                      |       | $                      | 2,337,916  |                  | $          | 1,837,398 |   |

 

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

 

3

----

 

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OFCASH FLOWS

(Unaudited)

(Dollars in thousands)

 
| ** **                                                                              | ** ** | **Nine Months Ended**  | ** ** |
|-----------------------------------------------------------------------------------------|------------|------------------------|------------|
| ** **                                                                              | ** ** | **September 30,** | ** ** |
| ** **                                                                              | ** ** | **2005**               | ** ** | **2004** | ** ** |
| ** **                                                                              | ** ** | ** **             | ** ** | **(restated)** | ** ** |
| Reconciliation of net income to net cash provided by  operating activities:             |       |                   |       |   |   |
| Net income                                                                              |       | $                      | 68,070     |   | $ | 67,548 |   |
| Add income items that do not affect cash:                                               |       |                   |       |   |   |
| Depreciation, depletion and amortization                                                |       | 92,339                 |       | 67,013 |   |
| Loss on sale of assets                                                                  |       | 214                    |       | 1,409 |   |
| Deferred income taxes                                                                   |       | 11,669                 |       | 36,589 |   |
| Non-cash change in fair value of derivatives                                            |       | 93,265                 |       | 14,414 |   |
| Cumulative effect of a change in accounting  principle                                  |       | —                 |       | (4,714 | ) |
| Compensation expense from common stock options and  restricted stock                    |       | 2,680                  |       | 482 |   |
| Other non-cash items, net                                                               |       | (1,480                 | )          | 1,986 |   |
|                                                                                    |       |                   |       |   |   |
| Adjustments to working capital to arrive at net cash  provided by operating activities: |       |                   |       |   |   |
| (Increase) decrease in trade accounts receivable                                        |       | (60,382                | )          | 27,003 |   |
| (Increase) in margin deposits                                                           |       | (102,784               | )          | (3,878 | ) |
| (Increase) in product inventory                                                         |       | (31,716                | )          | (37,738 | ) |
| (Increase) in other current assets                                                      |       | (18,752                | )          | (2,365 | ) |
| (Increase) decrease in other assets and liabilities,  net                               |       | (865                   | )          | 205 |   |
| Increase (decrease) in accounts payable                                                 |       | 49,159                 |       | (41,076 | ) |
| Increase (decrease) in accrued expenses                                                 |       | 48,251                 |       | (200 | ) |
|                                                                                    |       |                   |       |   |   |
| Net cash provided by operating activities                                               |       | 149,668                |       | 126,678 |   |
|                                                                                    |       |                   |       |   |   |
| Cash flows from investing activities:                                                   |       |                   |       |   |   |
|                                                                                    |       |                   |       |   |   |
| Purchases of property and equipment, including  acquisitions                            |       | (301,147               | )          | (147,103 | ) |
| (Contributions to) distributions from equity  investees                                 |       | (1,427                 | )          | 1,196 |   |
| Proceeds from the dispositions of property and  equipment                               |       | 1,856                  |       | 1,022 |   |
|                                                                                    |       |                   |       |   |   |
| Net cash used in investing activities                                                   |       | (300,718               | )          | (144,885 | ) |
|                                                                                    |       |                   |       |   |   |
| Cash flows from financing activities:                                                   |       |                   |       |   |   |
|                                                                                    |       |                   |       |   |   |
| Proceeds from exercise of common stock options                                          |       | 12,134                 |       | 6,760 |   |
| Change in balance of outstanding checks                                                 |       | 26,725                 |       | 22,624 |   |
| Borrowings under revolving credit facility                                              |       | 3,097,865              |       | 1,390,330 |   |
| Payments on revolving credit facility                                                   |       | (2,945,365             | )          | (1,346,830 | ) |
| Borrowings of long-term debt                                                            |       | 25,000                 |       | 100,000 |   |
| Payments on long-term debt                                                              |       | (35,000                | )          | (165,000 | ) |
| Debt issue costs paid                                                                   |       | (39                    | )          | (1,850 | ) |
| Payments for the redemption of preferred stock                                          |       | —                 |       | (1,930 | ) |
| Dividends paid                                                                          |       | (11,127                | )          | (9,294 | ) |
|                                                                                    |       |                   |       |   |   |
| Net cash provided by (used in) financing activities                                     |       | 170,193                |       | (5,190 | ) |
|                                                                                    |       |                   |       |   |   |
| Net increase (decrease) in cash and cash equivalents                                    |       | 19,143                 |       | (23,397 | ) |
|                                                                                    |       |                   |       |   |   |
| Cash and cash equivalents at beginning of period                                        |       | 390                    |       | 26,116 |   |
|                                                                                    |       |                   |       |   |   |
| Cash and cash equivalents at end of period                                              |       | $                      | 19,533     |   | $ | 2,719 |   |

 

The accompanying notes are an integral part ofthe consolidated financial statements.

 

4

----

 

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OFOPERATIONS

(Unaudited)

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

 
| ** **                                                                                       | ** ** | **Three Months Ended** | ** ** | **Nine Months Ended**  | ** ** |
|--------------------------------------------------------------------------------------------------|------------|------------------------|------------|------------------------|------------|
| ** **                                                                                       | ** ** | **September 30,** | ** ** | **September 30,** | ** ** |
| ** **                                                                                       | ** ** | ** **             | ** ** | **Restated**           | ** ** | ** ** | ** ** | **Restated** | ** ** |
| ** **                                                                                       | ** ** | **2005**               | ** ** | **2004**               | ** ** | **2005** | ** ** | **2004** | ** ** |
| Revenues:                                                                                        |       |                   |       |                   |       |   |   |   |   |
| Sale of gas                                                                                      |       | $                      | 821,485    |                   | $          | 561,157 |   | $ | 2,195,791 |   | $ | 1,822,348 |   |
| Sale of natural gas liquids                                                                      |       | 191,559                |       | 124,464                |       | 474,009 |   | 319,400 |   |
| Gathering, processing and transportation revenue                                                 |       | 26,931                 |       | 25,080                 |       | 78,634 |   | 66,319 |   |
| Price risk management activities                                                                 |       | (79,850                | )          | (17,592                | )          | (88,893 | ) | (11,613 | ) |
| Other                                                                                            |       | 1,285                  |       | 570                    |       | 4,002 |   | 2,743 |   |
| Total revenues                                                                                   |       | 961,410                |       | 693,679                |       | 2,663,543 |   | 2,199,197 |   |
|                                                                                             |       |                   |       |                   |       |   |   |   |   |
| Costs and  expenses:                                                                             |       |                   |       |                   |       |   |   |   |   |
| Product purchases                                                                                |       | 834,911                |       | 585,774                |       | 2,249,781 |   | 1,845,282 |   |
| Plant and transportation operating expense                                                       |       | 31,031                 |       | 23,976                 |       | 85,561 |   | 68,165 |   |
| Oil and gas exploration and production expense                                                   |       | 28,289                 |       | 18,510                 |       | 77,244 |   | 55,432 |   |
| Depreciation, depletion and amortization                                                         |       | 32,462                 |       | 22,039                 |       | 92,339 |   | 67,013 |   |
| (Gain) loss on sale of assets                                                                    |       | 187                    |       | (230                   | )          | 214 |   | 1,409 |   |
| Selling and administrative expense                                                               |       | 15,961                 |       | 10,305                 |       | 46,030 |   | 37,506 |   |
| (Earnings) from equity investments                                                               |       | (2,638                 | )          | (1,542                 | )          | (7,018 | ) | (5,244 | ) |
| Loss from early extinguishment of debt                                                           |       | —                 |       | —                 |       | — |   | 10,662 |   |
| Interest expense                                                                                 |       | 4,764                  |       | 3,912                  |       | 12,317 |   | 15,065 |   |
| Total costs and expenses                                                                         |       | 944,967                |       | 662,744                |       | 2,556,468 |   | 2,095,290 |   |
|                                                                                             |       |                   |       |                   |       |   |   |   |   |
| Income before  taxes                                                                             |       | 16,443                 |       | 30,935                 |       | 107,075 |   | 103,907 |   |
| Provision for  income taxes:                                                                     |       |                   |       |                   |       |   |   |   |   |
| Current                                                                                          |       | 13,814                 |       | 1,949                  |       | 27,336 |   | 4,484 |   |
| Deferred                                                                                         |       | (8,106                 | )          | 9,521                  |       | 11,669 |   | 36,589 |   |
| Total provision for income taxes                                                                 |       | 5,708                  |       | 11,470                 |       | 39,005 |   | 41,073 |   |
|                                                                                             |       |                   |       |                   |       |   |   |   |   |
| Income before cumulative effect of change in  accounting principle                               |       | 10,735                 |       | 19,465                 |       | 68,070 |   | 62,834 |   |
|                                                                                             |       |                   |       |                   |       |   |   |   |   |
| Cumulative effect of change in accounting principle,  net of tax of $2,710                       |       | —                 |       | —                 |       | — |   | 4,714 |   |
|                                                                                             |       |                   |       |                   |       |   |   |   |   |
| Net income                                                                                       |       | 10,735                 |       | 19,465                 |       | 68,070 |   | 67,548 |   |
|                                                                                             |       |                   |       |                   |       |   |   |   |   |
| Preferred stock requirements                                                                     |       | —                 |       | —                 |       | — |   | (835 | ) |
|                                                                                             |       |                   |       |                   |       |   |   |   |   |
| Income attributable to common stock                                                              |       | $                      | 10,735     |                   | $          | 19,465 |   | $ | 68,070 |   | $ | 66,713 |   |
|                                                                                             |       |                   |       |                   |       |   |   |   |   |
| Net income per share of common stock before  cumulative effect of change in accounting principle |       | $                      | .14        |                   | $          | .26 |   | $ | .92 |   | $ | .86 |   |
|                                                                                             |       |                   |       |                   |       |   |   |   |   |
| Cumulative effect of change in accounting principle                                              |       | $                      | —     |                   | $          | — |   | $ | — |   | $ | .07 |   |
|                                                                                             |       |                   |       |                   |       |   |   |   |   |
| Earnings per share of common stock                                                               |       | $                      | .14        |                   | $          | .26 |   | $ | .92 |   | $ | .93 |   |
|                                                                                             |       |                   |       |                   |       |   |   |   |   |
| Weighted average shares of common stock outstanding                                              |       | 74,373,114             |       | 73,778,729             |       | 74,251,936 |   | 71,887,962 |   |
|                                                                                             |       |                   |       |                   |       |   |   |   |   |
| Income attributable to common stock – assuming  dilution                                    |       | $                      | 10,735     |                   | $          | 19,465 |   | $ | 68,070 |   | $ | 66,713 |   |
|                                                                                             |       |                   |       |                   |       |   |   |   |   |
| Earnings per share of common  stock – assuming dilution                                     |       | $                      | .14        |                   | $          | .26 |   | $ | .90 |   | $ | .91 |   |
|                                                                                             |       |                   |       |                   |       |   |   |   |   |
| Weighted average shares of common stock outstanding  - assuming dilution                         |       | 76,556,084             |       | 74,998,146             |       | 75,914,906 |   | 72,934,517 |   |

 

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

 

5

----

 

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                                            |       | —        |       | —          |       | —     |       | —       |       | —           |       | —         |       | 68,070       |       | —            |       | 68,070            |       |
| Translation adjustments                               |       | —        |       | —          |       | —     |       | —       |       | —           |       | —         |       | —       |       | (1,004            | )          | (1,004            | )          |
| Other comprehensive income                            |       |          |       |            |       |       |       |         |       |             |       |           |       |         |       |              |       |              |       |
| From equity investees                                 |       | —        |       | —          |       | —     |       | —       |       | —           |       | —         |       | —       |       | 66                |       | 66                |       |
| Reclassification adjustment for settled contracts     |       | —        |       | —          |       | —     |       | —       |       | —           |       | —         |       | —       |       | (827              | )          | (827              | )          |
| Changes in fair value of outstanding hedge positions  |       | —        |       | —          |       | —     |       | —       |       | —           |       | —         |       | —       |       | (17,729           | )          | (17,729           | )          |
| Change in estimated ineffectiveness                   |       | —        |       | —          |       | —     |       | —       |       | —           |       | —         |       | —       |       | 51                |       | 51                |       |
| Fair value of new hedge positions                     |       | —        |       | —          |       | —     |       | —       |       | —           |       | —         |       | —       |       | (19,427           | )          | (19,427           | )          |
| Change in accumulated derivative comprehensive income |       | —        |       | —          |       | —     |       | —       |       | —           |       | —         |       | —       |       | (37,932           | )          | (37,932           | )          |
| Total comprehensive income, net of tax                |       | —        |       | —          |       | —     |       | —       |       | —           |       | —         |       | —       |       | —            |       | 29,200            |       |
| Stock options exercised                               |       | 683,078       |       | —          |       | 68         |       | —       |       | —           |       | 12,066         |       | —       |       | —            |       | 12,134            |       |
| Compensation expense from common stock options        |       | —        |       | —          |       | —     |       | —       |       | —           |       | 1,233          |       | —       |       | —            |       | 1,233             |       |
| Unearned compensation on restricted stock             |       | 373,390       |       | —          |       | 37         |       | —       |       | (10,207          | )          | 11,617         |       | —       |       | —            |       | 1,447             |       |
| Tax benefit related to stock options exercised        |       | —        |       | —          |       | —     |       | —       |       | —           |       | 1,884          |       | —       |       | —            |       | 1,884             |       |
| Dividends declared on common stock                    |       | —        |       | —          |       | —     |       | —       |       | —           |       | —         |       | (11,399      | )          | —            |       | (11,399           | )          |
|                                                  |       |          |       |            |       |       |       |         |       |             |       |           |       |         |       |              |       |              |       |
| Balance at September 30, 2005                    |       | 75,135,201    |       | 50,032          |       | $          | 7,535      |         | $          | (788             | )          | $              | (10,207    | )            | $          | 419,237           |       | $                 | 338,099    |   | $ | (34,608 | ) | $ | 719,268 |   |

 

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

 

6

----

 

WESTERN GAS RESOURCES, INC.

NOTES TO CONSOLIDATEDFINANCIAL STATEMENTS

(Unaudited)

 

***NOTE1 – GENERAL***

 

Wehave prepared the accompanying unaudited interim consolidated financialstatements under the rules and regulations of the Securities and Exchange Commission,or 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 for the year ended December 31,2004.  The interim consolidated financialstatements as of September 30, 2005 and for the three and nine-monthperiods ended September 30, 2005 and 2004 included herein are unauditedbut reflect, in the opinion of management, all adjustments (which include onlynormal recurring adjustments) necessary to fairly state the results for suchperiods.  The results of operations forthe three and nine-months ended September 30, 2005 are not necessarilyindicative of the results of operations expected for the year ended December 31,2005.

 

Wehave revised our classification in the Statement of Cash Flows for the ninemonths ended September 30, 2004, of the Change in the balance ofoutstanding checks, from a component of Net cash provided by operatingactivities to a component of Cash flows from financing activities.  This change in classification had the effectof decreasing previously reported cash provided by operating activities by$22.6 million for the nine months ended September 30, 2004, with acorresponding decrease in cash flows used in financing activities.

 

***RESTATEMENTOF CONSOLIDATED FINANCIAL STATEMENTS***

 

Upon adoption of FASB Statement No. 133, “Accountingfor Derivative Instruments and Hedging Activities”, or “FAS 133”, in 2001, we analyzed our gas storage and gastransportation contracts in detail, and determined that these contracts had thecharacteristics of a derivative 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 contracts andthe market for those contracts, we determined that these contracts do not meetthe definition of a derivative as: (i) the market for these types ofcontracts is not sufficiently liquid for us to receive fair value in a readymarket and (ii) if any contract is assigned, there is no assurance that wewill be relieved of our rights and obligations under that contract.  Accordingly, we have restated our auditedfinancial statements for the years from 2001 through 2004 and our unauditedfinancial statements for the first two quarters of 2005 as well as all quartersin 2004 and 2003.

 

Historically, the non-cash mark-to-market valuation ofthe gas storage and gas transportation contracts which, prior to therestatement were considered to be derivatives, effectively offset non-cashmark-to-market changes to the forward derivative contracts to sell our storedor transported natural gas.  The changesin both of these mark-to-market valuations were reflected in Price risk managementactivities on the Consolidated statement of operations and as reported in themarketing segment.  After the adjustmentsto correct the prior accounting for the gas storage and gas transportationcontracts, the non-cash mark-to-market of the forward derivative contract onthe sale of gas will fluctuate through earnings with changes in market pricesand will not be offset by a corresponding mark to market on the gas storage andtransportation contracts.  As the storedor transported natural gas is sold and the forward sale derivatives are settled,we will realize the benefit of the storage and transportation transactionsthrough 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/A for the period ended September 30,2004 as filed on November 23, 2004 (000s):

 
| ** **                                      | ** ** | **Three months ending**     | ** ** | **Nine months ending**      | ** ** |
|-------------------------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| ** **                                      | ** ** | **September 30, 2004** | ** ** | **September 30, 2004** | ** ** |
| Net income as previously reported               |       | $                           | 35,118     |                        | $          | 78,181 |   |
| Accounting correction for derivatives (pre-tax) |       | (24,576                     | )          | (16,577                     | )          |
| Tax impact of above                             |       | 8,923                       |       | 5,944                       |       |
| Net income as restated                          |       | $                           | 19,465     |                        | $          | 67,548 |   |

 

7

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The followingis a summary of the impact of these accounting adjustments on our ConsolidatedBalance Sheet and Consolidated Statement of Operations as previously reportedin the original Quarterly Report on Form 10-Q/A for the period ended September 30,2004 as filed on November 23, 2004. The aforementioned restatement adjustments do not affect cash flowsprovided by operating activities, net cash used in investing activities and netcash provided by (used in) financing activities, although certain components ofcash flows provided by operating activities have been restated.

 

Consolidated Balance Sheet

 
| ** **                                                   | ** ** | **December 31, 2004** | ** ** |
|--------------------------------------------------------------|------------|----------------------------|------------|
| ** **                                                   | ** ** | **As**                     | ** ** | **As** | ** ** |
| **(000s)**                                                   | ** ** | **Reported**               | ** ** | **Restated** | ** ** |
| ** **                                                   | ** ** | ** **                 | ** ** | ** ** | ** ** |
| Assets:                                                      |       |                       |       |   |   |
| Current assets  from price risk management activities        |       | 22,238                     |       | 19,893 |   |
| Long-term assets  from price risk management activities      |       | 618                        |       | 249 |   |
| Total Assets                                                 |       | $                          | 1,840,112  |   | $ | 1,837,398 |   |
|                                                         |       |                       |       |   |   |
| Liabilities and  Stockholders’ equity                   |       |                       |       |   |   |
| Current  liabilities from price risk management activities   |       | 11,099                     |       | 4,321 |   |
| Deferred income  taxes                                       |       | —                     |       | 5,618 |   |
| Long-term  liabilities from price risk management activities |       | 417                        |       | 180 |   |
| Deferred income  taxes payable, net                          |       | 247,893                    |       | 243,835 |   |
| Total  liabilities                                           |       | 1,158,084                  |       | 1,152,629 |   |
|                                                         |       |                       |       |   |   |
| Stockholders’  equity                                   |       |                       |       |   |   |
| Retained  earnings                                           |       | 278,687                    |       | 281,428 |   |
| Total  stockholders’ equity                             |       | 682,028                    |       | 684,769 |   |
| Total  liabilities and stockholders’ equity             |       | $                          | 1,840,112  |   | $ | 1,837,398 |   |

 

Consolidated Statement ofOperations

 
| ** **                                                                                     | ** ** | **Three Months Ended,**     | ** ** | **Nine Months Ended,**      | ** ** |
|------------------------------------------------------------------------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| ** **                                                                                     | ** ** | **September 30, 2004** | ** ** | **September 30, 2004** | ** ** |
| ** **                                                                                     | ** ** | **As**                      | ** ** | **As**                      | ** ** | **As** | ** ** | **As** | ** ** |
| **(000s)**                                                                                     | ** ** | **Reported**                | ** ** | **Restated**                | ** ** | **Reported** | ** ** | **Restated** | ** ** |
| ** **                                                                                     | ** ** | ** **                  | ** ** | ** **                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Revenues:                                                                                      |       |                        |       |                        |       |   |   |   |   |
|                                                                                           |       |                        |       |                        |       |   |   |   |   |
| Price risk management activities                                                               |       | 6,984                       |       | (17,592                     | )          | 4,964 |   | (11,613 | ) |
| Total revenues                                                                                 |       | $                           | 718,255    |                        | $          | 693,679 |   | $ | 2,215,774 |   | $ | 2,199,197 |   |
|                                                                                           |       |                        |       |                        |       |   |   |   |   |
| Income before income taxes                                                                     |       | 55,511                      |       | 30,935                      |       | 120,484 |   | 103,907 |   |
| Provision for income taxes:                                                                    |       |                        |       |                        |       |   |   |   |   |
| Deferred                                                                                       |       | 18,444                      |       | 9,521                       |       | 42,533 |   | 36,589 |   |
| Total provision for income taxes                                                               |       | 20,393                      |       | 11,470                      |       | 47,017 |   | 41,073 |   |
| Income before cumulative effect of change in  accounting principle                             |       | 35,118                      |       | 19,465                      |       | 73,467 |   | 62,834 |   |
| Net income                                                                                     |       | 35,118                      |       | 19,465                      |       | 78,181 |   | 67,548 |   |
| Income attributable to common stock                                                            |       | 35,118                      |       | 19,465                      |       | 77,346 |   | 66,713 |   |
| Earnings per share of common stock before cumulative  effect of change in accounting principle |       | 0.48                        |       | 0.26                        |       | 1.01 |   | 0.86 |   |
| Earnings per share of common stock                                                             |       | 0.48                        |       | 0.26                        |       | 1.08 |   | 0.93 |   |
| Income attributable to common stock - assuming  dilution                                       |       | 35,118                      |       | 19,465                      |       | 77,346 |   | 66,713 |   |
| Earnings per share of common stock - assuming  dilution                                        |       | $                           | 0.47       |                        | $          | 0.26 |   | $ | 1.06 |   | $ | 0.91 |   |

 

8

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Thenet impact of this restatement was to adjust Net income by ($15.7) million forthe three months ended September 30, 2004 and ($10.6) million for the ninemonths ended September 30, 2004.  The net impact of this restatement was to adjust Earnings per share ofcommon stock – assuming dilution by ($0.21) for the three months ended September 30,2004 and ($0.15) for the nine months ended September 30, 2004

 

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

 

***Earnings Per Share of Common Stock*.**  Earnings per share of common stock arecomputed by dividing income attributable to common stock by the weightedaverage shares of common stock outstanding. In addition, earnings per share of common stock - assuming dilution iscomputed by dividing income attributable to common stock by the weightedaverage shares of common stock outstanding as adjusted for potential common shares.  Income attributable to common stock is netincome less preferred stock dividends.  The following table presents the dividends declared by us for each classof our outstanding equity securities (dollars in thousands, except per shareamounts):

 
| ** **                     | ** ** | **Quarter Ended September 30,** | ** ** | **Nine Months Ended September 30,** | ** ** |
|--------------------------------|------------|--------------------------------------|------------|------------------------------------------|------------|
| ** **                     | ** ** | **2005**                             | ** ** | **2004**                                 | ** ** | **2005** | ** ** | **2004** | ** ** |
| Common Stock                   |       | $                                    | 3,774      |                                     | $          | 3,697 |   | $ | 11,399 |   | $ | 9,146 |   |
| Preferred Stock                |       | —                               |       | —                                   |       | — |   | 835 |   |
| Total Dividends  Declared      |       | $                                    | 3,774      |                                     | $          | 3,697 |   | $ | 11,399 |   | $ | 9,981 |   |
|                           |       |                                 |       |                                     |       |   |   |   |   |
| Dividends  Declared Per Share: |       |                                 |       |                                     |       |   |   |   |   |
| Common Stock                   |       | $                                    | 0.05       |                                     | $          | 0.05 |   | $ | 0.15 |   | $ | 0.15 |   |
| Preferred Stock                |       | —                               |       | —                                   |       | — |   | $ | .66 |   |

 

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 weighted average shares of common stock outstanding tothe weighted average common shares outstanding – assuming dilution.

 
| ** **                                                               | ** ** | **Quarter Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|--------------------------------------------------------------------------|------------|---------------------------------------|------------|-------------------------------------------|------------|
| ** **                                                               | ** ** | **2005**                              | ** ** | **2004**                                  | ** ** | **2005** | ** ** | **2004** | ** ** |
| Weighted average shares of common stock outstanding                      |       | 74,373,114                            |       | 73,778,729                                |       | 74,251,936 |   | 71,887,962 |   |
| Potential common shares from:                                            |       |                                  |       |                                      |       |   |   |   |   |
| Common stock options and restricted stock                                |       | 2,182,970                             |       | 1,219,417                                 |       | 1,662,970 |   | 1,046,555 |   |
| $ 2.625 Cumulative Convertible Preferred Stock                      |       | —                                |       | —                                    |       | — |   | — |   |
| Weighted average shares of common stock outstanding  - assuming dilution |       | 76,556,084                            |       | 74,998,146                                |       | 75,914,906 |   | 72,934,517 |   |

 

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

 

***Accumulated OtherComprehensive Income. ***Included in Accumulated other comprehensive (loss) income at September 30,2005 were unrealized losses of $37.5 million, which is net of $21.6 million ofdeferred taxes,  from the fair value ofderivatives designated as cash flow hedges and unrealized losses of $2.9million, which is net of $1.0 million of deferred taxes, as a result ofcumulative foreign currency translation adjustments.

 

Thegains and losses currently reflected in Accumulated other comprehensive (loss)income will be reclassified to earnings as the hedged gas or NGLs aresold.  Based on the prices for our productson September 30, 2005, approximately $37.5 million of losses inAccumulated other comprehensive (loss) income will be reclassified to earnings,of which $17.9 million will be reclassified in the remainder of 2005.

 

9

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##### ***Revenue Recognition.  ***Inthe Gas Gathering, Processing and Treating segment, we recognize revenue forour services at the time the service is performed. We record revenue from ourgas and natural gas liquid, or NGL, marketing activities, including sales ofour equity production, upon transfer of title. In accordance with Emerging Issues Task Force, or EITF, 03-11 “ReportingRealized Gains and Losses on Derivative Instruments That are Subject to FASBStatement No. 133, Accounting for Derivative Instruments and HedgingActivities, and Not Held for Trading Purposes as Defined in Issue No. 02-3”,we record revenue on our physicalgas and NGL marketing activities on a gross basis versus sales net of purchasesbasis because we obtain title to all the gas and NGLs that we buy includingthird-party purchases; we bear the risk of loss and credit exposure on thesetransactions; and it is our intention upon entering these contracts to takephysical delivery of the product.  Gasimbalances on our production are accounted for using the sales method.  Gas imbalances on our production at September 30,2005 and 2004 are immaterial.  For ourmarketing activities, we utilize mark-to-market accounting for ourderivatives.  In our Transportationsegment, we realize revenue on a monthly basis from firm capacity contractsunder which the shipper pays for transport capacity whether or not the capacityis used and from interruptible contracts where a fee is charged based uponvolumes delivered into the pipeline.

 

##### ***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 nine months ended September 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 TradePublications. *** In 2003, we learned that several employees inour marketing department furnished inaccurate information regarding natural gastransactions to energy publications, which compile and report energy indexprices.  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 nine months ended September 30, 2004 werereduced by $0.09.   In the second quarterof 2005, we reached a settlement of a related claim with a private litigant for$3.8 million after-tax, or $0.05 per common share for the nine months ended September 30,2005.  For additional information on thisrelated claim, see Legal Proceedings in these Notes to Consolidated FinancialStatements.

 

***Income Taxes. ***The Total provision forincome taxes, as a percentage of Income before taxes, was approximately 34.7%and 36.4%, respectively, during the quarter and nine months ended September 30,2005 as compared to 37.1% and 39.5%, respectively, in the same periods of2004.  The decrease in the percentage ofincome taxes in the nine-month periods is primarily due to the civil penaltypaid to the CFTC in 2004, which was non-deductible for tax purposes.

 

***Supplementary Cash Flow Information*.**  Interest paid was $18.4 million and  $17.6 million for the nine months ended September 30,2005 and 2004, respectively. A total of$20.2 million and $7.7 million was paid in income taxes in the nine monthsended September 30, 2005 and 2004, respectively.  Asset retirement obligation assets of$9.4 million were recorded for capitalized assets and asset retirementobligation liabilities of $11.0 million were recorded for the nine months endedSeptember 30, 2005.  The assetretirement and associated obligations are non-cash transactions forpresentation on the Consolidated Statement of Cash Flows.

 

***NOTE 2 - DERIVATIVE INSTRUMENTS AND HEDGINGACTIVITIES.***

 

A netloss was recognized in earnings through Sale of gas and Sale of natural gasliquids during the three and nine months ended September 30, 2005 from hedgingactivities of $2.7 million and $2.9 million, respectively.  Also during these periods we recognized aloss from hedge ineffectiveness of $30,000 and $208,000, respectively, throughPrice risk management activities.   At September 30,2005, we had margin deposits posted of $110.7 million, which is included inTrade accounts receivable, net.  Theamount of margin posted has decreased to $53.8 million on November 7,2005, and we will receive these margin deposits back as these positions expireduring the fourth quarter of 2005 and the first quarter of 2006 or as commodityprices decline.

 

10

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***NOTE 3 - 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 option price.  This tax benefit is credited to Additionalpaid-in capital.

 

In the first nine months of 2005, we granted933,000 options to purchase our common stock at the market based on the averageclosing price for the ten days prior to grant, and 374,000 shares of restrictedcommon stock to our employees.  Inconjunction with the grant of restricted common stock, we will record ascompensation expense over the three-year vesting period, the value of therestricted common stock on the date of grant. Accordingly, we recorded compensation expense of $984,000 and $1.4million, respectively, related to our restricted stock in the third quarter andnine months ended September 30, 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 nine months ended September 30, 2005 and 2004, respectively.

 
| ** **                 | ** ** | **Quarter Ended September 30,** | ** ** | **Nine Months Ended September 30,** | ** ** |
|----------------------------|------------|--------------------------------------|------------|------------------------------------------|------------|
| ** **                 | ** ** | **2005**                             | ** ** | **2004**                                 | ** ** | **2005** | ** ** | **2004** | ** ** |
| 1999 Plan                  |       | —                               |       | 141,000                                  |       | — |   | 141,000 |   |
| 2002 Plan                  |       | 17,000                               |       | 846,000                                  |       | 154,000 |   | 921,000 |   |
| 2002 Directors’  Plan |       | —                               |       | —                                   |       | 32,000 |   | 32,000 |   |
| 2005 Plan                  |       | —                               |       | —                                   |       | 747,000 |   | — |   |
| Total options  granted     |       | 17,000                               |       | 987,000                                  |       | 933,000 |   | 1,094,000 |   |

 

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

 
| ** **                 | ** ** | **Quarter Ended September 30,** | ** ** | **Nine Months Ended September 30,** | ** ** |
|----------------------------|------------|--------------------------------------|------------|------------------------------------------|------------|
| ** **                 | ** ** | **2005**                             | ** ** | **2004**                                 | ** ** | **2005** | ** ** | **2004** | ** ** |
| 1999 Plan                  |       | —                               |       | $                                        | 13.12      |   | — |   | $ | 13.12 |   |
| 2002 Plan                  |       | $                                    | 18.20      |                                     | $          | 13.09 |   | $ | 15.36 |   | $ | 13.09 |   |
| 2002 Directors’  Plan |       | —                               |       | —                                   |       | $ | 14.79 |   | $ | 12.13 |   |
| 2005 Plan                  |       | —                               |       | —                                   |       | $ | 13.25 |   | — |   |
|                            |            |                                      |            |                                          |            |  |  |  |  |  |  |  |  |

 

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

 
| ** **                     | ** ** | **Quarter Ended September 30,  2005** | ** ** | **Nine Months Ended September 30,  2005** | ** ** |
|--------------------------------|------------|--------------------------------------------|------------|------------------------------------------------|------------|
| ** **                     | ** ** | **2002  Plan**                             | ** ** | **2002  Directors’  Plan**                | ** ** | **2005  Plan** | ** ** | **2002 Plan** | ** ** | **2002  Directors’  Plan** | ** ** | **2005 Plan** | ** ** |
| Risk-free interest rate        |       | 4.52                                       | %          | —                                         |       | — |   | 4.37 | % | 4.38 | % | 4.27 | % |
| Expected life (in years)       |       | 7                                          |       | —                                         |       | — |   | 7 |   | 7 |   | 7 |   |
| Expected volatility            |       | 36                                         | %          | —                                         |       | — |   | 37 | % | 37 | % | 37 | % |
| Expected dividends (quarterly) |       | $                                          | 0.05       |                                           | —     |   | — |   | $ | 0.05 |   | $ | 0.05 |   | $ | 0.05 |   |
|                                |            |                                            |            |                                                |            |  |  |  |  |  |  |  |  |  |  |  |  |

 

11

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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 of commonstock - assuming dilution would approximate the pro forma amounts below(dollars in thousands, except per share amounts):

 
| ** **                                                                                                                                     | ** ** | **Quarter Ended September 30,** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------|------------|
| ** **                                                                                                                                     | ** ** | ** **                           | ** ** | ** ** | ** ** | **Restated** | ** ** | **Restated** | ** ** |
| ** **                                                                                                                                     | ** ** | **2005**                             | ** ** | **2005** | ** ** | **2004** | ** ** | **2004** | ** ** |
| ** **                                                                                                                                     | ** ** | **As Reported**                      | ** ** | **Pro Forma** | ** ** | **As Reported** | ** ** | **Pro Forma** | ** ** |
|                                                                                                                                           |       |                                 |       |   |   |   |   |   |   |
| Net income                                                                                                                                     |       | $                                    | 10,735     |   | $ | 8,731 |   | $ | 19,465 |   | $ | 17,758 |   |
| Net income attributable to common stock                                                                                                        |       | 10,735                               |       | 8,731 |   | 19,465 |   | 17,758 |   |
| Earnings per share of common stock                                                                                                             |       | 0.14                                 |       | 0.12 |   | 0.26 |   | 0.24 |   |
| Earnings per share of common stock - assuming  dilution                                                                                        |       | 0.14                                 |       | 0.11 |   | 0.26 |   | 0.24 |   |
| Stock-based employee compensation cost, net of  related tax effects, included in net income                                                    |       | 311                                  |       | — |   | 4 |   | — |   |
| Stock-based employee compensation cost, net of  related tax effects, includable in net income if the fair value based method  had been applied |       | $                                    | —     |   | $ | 2,378 |   | $ | — |   | $ | 1,711 |   |

 
| ** **                                                                                                                                     | ** ** | **Nine Months Ended September 30,** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------------------|------------|
| ** **                                                                                                                                     | ** ** | ** **                               | ** ** | ** ** | ** ** | **Restated** | ** ** | **Restated** | ** ** |
| ** **                                                                                                                                     | ** ** | **2005**                                 | ** ** | **2005** | ** ** | **2004** | ** ** | **2004** | ** ** |
| ** **                                                                                                                                     | ** ** | **As Reported**                          | ** ** | **Pro Forma** | ** ** | **As Reported** | ** ** | **Pro Forma** | ** ** |
| Net income                                                                                                                                     |       | $                                        | 68,070     |   | $ | 61,820 |   | $ | 67,548 |   | $ | 63,533 |   |
| Net income attributable to common stock                                                                                                        |       | 68,070                                   |       | 61,820 |   | 66,713 |   | 62,698 |   |
| Earnings per share of common stock                                                                                                             |       | 0.92                                     |       | 0.83 |   | 0.93 |   | 0.87 |   |
| Earnings per share of common stock –assuming  dilution                                                                                    |       | 0.90                                     |       | 0.82 |   | 0.91 |   | 0.87 |   |
| Stock-based employee compensation cost, net of  related tax effects, included in net income                                                    |       | 614                                      |       | — |   | 305 |   | — |   |
| Stock-based employee compensation cost, net of  related tax effects, includable in net income if the fair value based method  had been applied |       | $                                        | —     |   | $ | 6,864 |   | $ | — |   | $ | 4,320 |   |

 

***NOTE 4 - 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, we connect producers’ wells(including those of our Exploration and Production segment) to our gatheringsystems for delivery to our processing or treating plants, process the naturalgas to extract NGLs and treat the natural gas in order to meet pipelinespecifications.  In some areas, where noprocessing is required, we gather and compress producers’ gas and deliver it topipelines for further delivery to market. Except for volumes taken in kind by our producers, the Marketing segmentsells the residue gas and NGLs extracted at most of our facilities.

 

Substantiallyall gas flowing through our gathering, processing and treating facilities issupplied under three types of contracts providing for the purchase, treating orprocessing of natural gas for periods ranging from one month to twenty years orin some cases for the life of the oil and gas lease.  Approximately 74% of our plant facilities’gross margin, or revenues at the plant less product purchases, for the month ofSeptember 2005 was pursuant to percentage-of-proceeds agreements in whichwe are 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 andthe NGLs.

 

Approximately16% of our plant facilities’ gross margin for the month of September 2005was pursuant to contracts that are primarily fee-based from which we receive aset fee for each Mcf of gas gathered and/or processed. This type of contract

 

12

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provides us with a steadyrevenue stream that is not dependent on commodity prices, except to the extentthat low prices may cause a producer to delay drilling.

 

Approximately10% of our plant facilities’ gross margin for the month of September 2005was pursuant to contracts with “keepwhole” arrangements, the majority of whichalso include fees for gathering, compression or treating services, or wellheadpurchase contracts.  Under keepwholecontracts, we retain the NGLs recovered by the processing facility and keep theproducers whole by returning to the producers at the tailgate of the plant anamount of residue gas equal on a Btu basis to the natural gas received at theplant inlet.  The “keepwhole” componentof the contracts permits us to benefit when the value of the NGLs is greater asa liquid than as a portion of the residue gas stream.  However, we are adversely affected when thevalue of the NGLs is lower as a liquid than as a portion of the residue gasstream.

 

***Explorationand Production.*** The activities of the Exploration and Production segment include theexploration and development of gas properties primarily in the Rocky Mountain areaand other unconventional gas plays, including those where our gathering and/orprocessing facilities are located.  TheMarketing segment sells the majority of the production from these propertiesand remits to the Exploration and Production segment all of the proceeds fromthe sales of its gas, net of transportation charges.

 

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 provenreserves.  A determination as to whethera well has found proven reserves is made shortly after drilling is completed.The determination is based upon a process that relies on interpretations ofavailable geological, geophysical, and engineering data.  If an exploratory well is determined to beunsuccessful, the capitalized drilling costs will be charged to expense in theperiod the determination is made.  If anexploratory well requires a major capital expenditure before production canbegin, the cost of drilling the exploratory well will continue to be carried asan asset pending determination of whether proven reserves have been found onlyas long as: i) the well has found a sufficient quantity of reserves to justifyits completion as a producing well if the required capital expenditure is made,and ii) the drilling of additional exploratory wells is under way or firmlyplanned for the near future. If the drilling of additional exploratory wells inthe area is not under way or firmly planned, or if the well has not found acommercially producible quantity of reserves, the exploratory well is assumedto be impaired, and its costs are charged to expense.

 

The following tablereflects the net changes in capitalized exploratory well costs during the ninemonths ended September 30, 2005 (dollars in thousands).

 
| ** **                                                                                           | ** ** | **Nine Months Ended  September 30, 2005** | ** ** |
|------------------------------------------------------------------------------------------------------|------------|------------------------------------------------|------------|
| Beginning balance at December 31, 2004                                                          |       | $                                              | 48,546     |   |
| Additions to capitalized exploratory well costs  pending the determination of proven reserves        |       | 60,059                                         |       |
| Reclassifications to wells, facilities, and  equipment based on the determination of proved reserves |       | (11,239                                        | )          |
| Capitalized exploratory well costs charged to  expense                                               |       | (1,597                                         | )          |
| Ending balance at September 30, 2005                                                            |       | $                                              | 95,769     |   |

 

Substantially all of our exploratory wells thathave been capitalized for a period greater than one year are located in thePowder River Basin.  In this basin, wedrill wells into various coal seams.  Inorder to produce gas from the coal seams, a period of dewatering lasting from afew to twenty-four months, or in some cases longer, is required prior toobtaining sufficient gas production to justify capital expenditures forcompression and gathering, and to classify the reserves as proven.  In order to accelerate the dewatering time,we drill additional exploratory wells in these areas.

 

***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 which areimmaterial for separate presentation.

 

***Transportation.***  The Transportation segment reflects theoperations of Western’s MIGC, Inc. and MGTC, Inc. pipelines.   The majority of the revenue presented inthis segment is derived from transportation of residue gas for our Marketing

 

13

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segmentand other third parties.  TheTransportation segments’ firm capacity contracts range in duration from fifteenmonths to approximately thirteen years.

 

***SegmentInformation.*** The following tables set forth our segmentinformation as of and for the quarter and nine months ended September 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.

 

**Quarter Ended September 30, 2005**

 
| ** **                                       | ** ** | **Gas Gathering  and Processing** | ** ** | **Exploration  and  Production** | ** ** | **Marketing** | ** ** | **Trans-  portation** | ** ** | **Other** | ** ** | **Eliminating  Entries** | ** ** | **Total** | ** ** |
|--------------------------------------------------|------------|-----------------------------------|------------|----------------------------------|------------|---------------|------------|-----------------------|------------|-----------|------------|--------------------------|------------|-----------|------------|
|                                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Revenues from unaffiliated customers:            |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Sale of gas                                      |       | $                                 | 1,297      |                             | $          | 2,643         |       | $                     | 816,395    |      | $          | 293                      |       | $         | —     |   | $ | — |   | $ | 820,628 |   |
| Sale of natural gas liquids                      |       | 239                               |       | —                           |       | 194,861       |       | —                |       | —    |       | —                   |       | 195,100   |       |
| Equity hedges:                                   |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Residue                                          |       | 185                               |       | 672                              |       | —        |       | —                |       | —    |       | —                   |       | 857       |       |
| Liquids                                          |       | (3,541                            | )          | —                           |       | —        |       | —                |       | —    |       | —                   |       | (3,541    | )          |
| Gathering, processing and transportation revenue |       | 25,278                            |       | —                           |       | —        |       | 1,653                 |       | —    |       | —                   |       | 26,931    |       |
| Total revenues from unaffiliated customers:      |       | 23,458                            |       | 3,315                            |       | 1,011,256     |       | 1,946                 |       | —    |       | —                   |       | 1,039,975 |       |
|                                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Inter-segment sales                              |       | 370,775                           |       | 102,890                          |       | 21,235        |       | 3,493                 |       | 9         |       | (498,402                 | )          | —    |       |
| Price risk management activities                 |       | 44                                |       | 4,440                            |       | (84,334       | )          | —                |       | —    |       | —                   |       | (79,850   | )          |
| Interest Income                                  |       | 0                                 |       | 6                                |       | 2             |       | 1                     |       | 14,232    |       | (14,241                  | )          | —    |       |
| Other, net                                       |       | 968                               |       | 8                                |       | (6            | )          | —                |       | 315       |       | —                   |       | 1,285     |       |
| Total revenues                                   |       | 395,245                           |       | 110,659                          |       | 948,153       |       | 5,440                 |       | 14,556    |       | (512,643                 | )          | 961,410   |       |
|                                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Product purchases                                |       | 297,526                           |       | 916                              |       | 1,023,022     |       | 937                   |       | 0         |       | (487,490                 | )          | 834,911   |       |
| Plant and transportation operating expense       |       | 30,609                            |       | 25                               |       | 0             |       | 1,503                 |       | —    |       | (1,106                   | )          | 31,031    |       |
| Oil and gas exploration and production expense   |       | 0                                 |       | 38,103                           |       | —        |       | —                |       | —    |       | (9,814                   | )          | 28,289    |       |
| (Earnings) from equity investments               |       | (2,638                            | )          | —                           |       | —        |       | —                |       | —    |       | —                   |       | (2,638    | )          |
| Segment operating profit                         |       | 69,748                            |       | 71,615                           |       | (74,869       | )          | 3,000                 |       | 14,556    |       | (14,233                  | )          | 69,817    |       |
|                                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Depreciation, depletion and amortization         |       | 11,646                            |       | 18,357                           |       | 35            |       | 497                   |       | 1,927     |       |                     |       | 32,462    |       |
| Selling and administrative expense               |       | —                            |       | —                           |       | —        |       | —                |       | 15,970    |       | (9                       | )          | 15,961    |       |
| (Gain) loss from sale of assets                  |       | (29                               | )          | 0                                |       | —        |       | 216                   |       | —    |       | —                   |       | 187       |       |
| Interest expense                                 |       | —                            |       | (3                               | )          | 330           |       | (233                  | )          | 18,911    |       | (14,241                  | )          | 4,764     |       |
| Income before tax                                |       | $                                 | 58,131     |                             | $          | 53,261        |       | $                     | (75,234    | )         | $          | 2,520                    |       | $         | (22,252    | ) | $ | 17 |   | $ | 16,443 |   |
|                                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Identifiable assets:                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Equity investments                               |       | $                                 | 34,957     |                             | —     |          | —     |                  | $          | 877       |       | $                        | 935,443    |      | $          | (931,046 | ) | $ | 40,231 |   |
| Property and equipment                           |       | 762,999                           |       | $                                | 579,021    |          | $          | 12                    |       | 38,081    |       | 59,844                   |       | —    |       | 1,439,957 |   |
| Other allocated assets                           |       | 10,259                            |       | 21,802                           |       | 259,445       |       | 39,027                |       | 609,676   |       | (82,481                  | )          | 857,728   |       |
| Total identifiable assets                        |       | $                                 | 808,215    |                             | $          | 600,823       |       | $                     | 259,457    |      | $          | 77,985                   |       | $         | 1,604,963  |   | $ | (1,013,527 | ) | $ | 2,337,916 |   |

 

14

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**Quarter Ended September 30, 2004**

**(Restated)**

 
| ** **                                       | ** ** | **Gas Gathering  and Processing** | ** ** | **Exploration  and  Production** | ** ** | **Marketing** | ** ** | **Trans-  portation** | ** ** | **Other** | ** ** | **Eliminating  Entries** | ** ** | **Total** | ** ** |
|--------------------------------------------------|------------|-----------------------------------|------------|----------------------------------|------------|---------------|------------|-----------------------|------------|-----------|------------|--------------------------|------------|-----------|------------|
|                                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Revenues from unaffiliated customers:            |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Sale of gas                                      |       | $                                 | 878        |                             | $          | 2,375         |       | $                     | 557,315    |      | $          | 282                      |       | $         | —     |   | $ | — |   | $ | 560,850 |   |
| Sale of natural gas liquids                      |       | (559                              | )          | —                           |       | 130,057       |       | —                |       | —    |       | —                   |       | 129,498   |       |
| Equity hedges:                                   |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Residue                                          |       | (16                               | )          | 324                              |       | —        |       | —                |       | —    |       | —                   |       | 308       |       |
| Liquids                                          |       | (5,035                            | )          | —                           |       | —        |       | —                |       | —    |       | —                   |       | (5,035    | )          |
| Gathering, processing and transportation revenue |       | 23,469                            |       | —                           |       | —        |       | 1,611                 |       | —    |       | —                   |       | 25,080    |       |
| Total revenues from unaffiliated customers:      |       | 18,737                            |       | 2,699                            |       | 687,372       |       | 1,893                 |       | —    |       | —                   |       | 710,701   |       |
|                                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Inter-segment sales                              |       | 257,310                           |       | 62,547                           |       | 12,601        |       | 3,560                 |       | —    |       | (336,018                 | )          | —    |       |
| Price risk management activities                 |       | (30                               | )          | —                           |       | (17,562       | )          | —                |       | —    |       | —                   |       | (17,592   | )          |
| Interest Income                                  |       | —                            |       | 1                                |       | —        |       | 1                     |       | 5,460     |       | (5,462                   | )          | —    |       |
| Other, net                                       |       | 112                               |       | 9                                |       | (42           | )          | 2                     |       | 489       |       | —                   |       | 570       |       |
| Total revenues                                   |       | 276,129                           |       | 65,256                           |       | 682,369       |       | 5,456                 |       | 5,949     |       | (341,480                 | )          | 693,679   |       |
|                                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Product purchases                                |       | 210,347                           |       | 636                              |       | 700,209       |       | 867                   |       | —    |       | (326,285                 | )          | 585,774   |       |
| Plant and transportation operating expense       |       | 22,976                            |       | 7                                |       | 4             |       | 1,848                 |       | —    |       | (859                     | )          | 23,976    |       |
| Oil and gas exploration and production expense   |       | —                            |       | 27,468                           |       | —        |       | —                |       | —    |       | (8,958                   | )          | 18,510    |       |
| (Earnings) from equity investments               |       | (1,542                            | )          | —                           |       | —        |       | —                |       | —    |       | —                   |       | (1,542    | )          |
| Segment operating profit                         |       | 44,348                            |       | 37,145                           |       | (17,844       | )          | 2,741                 |       | 5,949     |       | (5,378                   | )          | 66,961    |       |
|                                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Depreciation, depletion and amortization         |       | 9,769                             |       | 10,245                           |       | 35            |       | 415                   |       | 1,575     |       | —                   |       | 22,039    |       |
| Selling and administrative expense               |       | —                            |       | —                           |       | —        |       | —                |       | 10,315    |       | (10                      | )          | 10,305    |       |
| (Gain) loss from sale of assets                  |       | (20                               | )          | (218                             | )          | —        |       | —                |       | 8         |       | —                   |       | (230      | )          |
| Interest expense                                 |       | —                            |       | (1                               | )          | 115           |       | (91                   | )          | 9,351     |       | (5,462                   | )          | 3,912     |       |
| Income before tax                                |       | $                                 | 34,599     |                             | $          | 27,119        |       | $                     | (17,994    | )         | $          | 2,417                    |       | $         | (15,300    | ) | $ | 94 |   | $ | 30,935 |   |
|                                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Identifiable assets:                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Equity investments                               |       | $                                 | 38,021     |                             | $          | —        |       | $                     | —     |      | $          | 3,822                    |       | $         | 698,127    |   | $ | (701,949 | ) | $ | 38,021 |   |
| Property and equipment                           |       | 641,898                           |       | 354,044                          |       | 18            |       | 37,226                |       | 52,986    |       | —                   |       | 1,086,172 |       |
| Other allocated assets                           |       | 6,214                             |       | 5,059                            |       | 36,228        |       | 24,598                |       | 385,054   |       | (52,446                  | )          | 404,707   |       |
| Total identifiable assets                        |       | $                                 | 686,133    |                             | $          | 359,103       |       | $                     | 36,246     |      | $          | 65,646                   |       | $         | 1,136,167  |   | $ | (754,395 | ) | $ | 1,528,900 |   |

 

15

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**Nine months ended September 30, 2005**

 
| ** **                                       | ** ** | **Gas Gathering  and Processing** | ** ** | **Exploration  and  Production** | ** ** | **Marketing** | ** ** | **Trans-  portation** | ** ** | **Other** | ** ** | **Eliminating  Entries** | ** ** | **Total** | ** ** |
|--------------------------------------------------|------------|-----------------------------------|------------|----------------------------------|------------|---------------|------------|-----------------------|------------|-----------|------------|--------------------------|------------|-----------|------------|
|                                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Revenues from unaffiliated customers:            |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Sale of gas                                      |       | $                                 | 2,026      |                             | $          | 9,718         |       | $                     | 2,179,964  |      | $          | 1,447                    |       | $         | —     |   | $ | — |   | $ | 2,193,155 |   |
| Sale of natural gas liquids                      |       | 290                               |       | —                           |       | 479,209       |       | —                |       | —    |       | —                   |       | 479,499   |       |
| Equity hedges:                                   |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Residue                                          |       | 360                               |       | 2,276                            |       | —        |       | —                |       | —    |       | —                   |       | 2,636     |       |
| Liquids                                          |       | (5,490                            | )          | —                           |       | —        |       | —                |       | —    |       | —                   |       | (5,490    | )          |
| Gathering, processing and transportation revenue |       | 73,724                            |       | (162                             | )          | —        |       | 5,072                 |       | —    |       | —                   |       | 78,634    |       |
| Total revenues from unaffiliated customers:      |       | 70,910                            |       | 11,832                           |       | 2,659,173     |       | 6,519                 |       | —    |       | —                   |       | 2,748,434 |       |
|                                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Inter-segment sales                              |       | 946,955                           |       | 250,533                          |       | 63,879        |       | 10,288                |       | 29        |       | (1,271,684               | )          | —    |       |
| Price risk management activities                 |       | (81                               | )          | 4,440                            |       | (93,252       | )          | —                |       | —    |       | —                   |       | (88,893   | )          |
| Interest Income                                  |       | —                            |       | 14                               |       | 20            |       | 1                     |       | 36,169    |       | (36,204                  | )          | —    |       |
| Other, net                                       |       | 3,161                             |       | 128                              |       | (3            | )          | —                |       | 716       |       | —                   |       | 4,002     |       |
| Total revenues                                   |       | 1,020,945                         |       | 266,947                          |       | 2,629,817     |       | 16,808                |       | 36,914    |       | (1,307,888               | )          | 2,663,543 |       |
|                                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Product purchases                                |       | 773,510                           |       | 3,280                            |       | 2,711,076     |       | 2,571                 |       | —    |       | (1,240,656               | )          | 2,249,781 |       |
| Plant and transportation operating expense       |       | 83,100                            |       | 193                              |       | 146           |       | 4,967                 |       | —    |       | (2,845                   | )          | 85,561    |       |
| Oil and gas exploration and production expense   |       | —                            |       | 105,397                          |       | —        |       | —                |       | —    |       | (28,153                  | )          | 77,244    |       |
| (Earnings) from equity investments               |       | (7,018                            | )          | —                           |       | —        |       | —                |       | —    |       | —                   |       | (7,018    | )          |
| Segment operating profit                         |       | 171,353                           |       | 158,077                          |       | (81,405       | )          | 9,270                 |       | 36,914    |       | (36,234                  | )          | 257,975   |       |
|                                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Depreciation, depletion and amortization         |       | 34,518                            |       | 50,885                           |       | 106           |       | 1,336                 |       | 5,494     |       | —                   |       | 92,339    |       |
| Selling and administrative expense               |       | —                            |       | —                           |       | —        |       | —                |       | 46,059    |       | (29                      | )          | 46,030    |       |
| (Gain) loss from sale of assets                  |       | (211                              | )          | 61                               |       | —        |       | 364                   |       | —    |       | —                   |       | 214       |       |
| Interest expense                                 |       | 5                                 |       | 1                                |       | 919           |       | (581                  | )          | 48,177    |       | (36,204                  | )          | 12,317    |       |
| Income before tax                                |       | $                                 | 137,041    |                             | $          | 107,130       |       | $                     | (82,430    | )         | $          | 8,151                    |       | $         | (62,816    | ) | $ | (1 | ) | $ | 107,075 |   |
|                                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Identifiable assets:                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Equity investments                               |       | $                                 | 34,957     |                             | —     |          | —     |                  | $          | 877       |       | $                        | 935,443    |      | $          | (931,046 | ) | $ | 40,231 |   |
| Property and equipment                           |       | 762,999                           |       | $                                | 579,021    |          | $          | 12                    |       | 38,081    |       | 59,844                   |       | —    |       | 1,439,957 |   |
| Other allocated assets                           |       | 10,259                            |       | 21,802                           |       | 259,445       |       | 39,027                |       | 609,676   |       | (82,481                  | )          | 857,728   |       |
| Total identifiable assets                        |       | $                                 | 808,215    |                             | $          | 600,823       |       | $                     | 259,457    |      | $          | 77,985                   |       | $         | 1,604,963  |   | $ | (1,013,527 | ) | $ | 2,337,916 |   |

 

16

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**Nine months ended September 30, 2004**

**(Restated)**

 
| ** **                                       | ** ** | **Gas Gathering  and Processing** | ** ** | **Exploration  and  Production** | ** ** | **Marketing** | ** ** | **Trans-  portation** | ** ** | **Other** | ** ** | **Eliminating  Entries** | ** ** | **Total** | ** ** |
|--------------------------------------------------|------------|-----------------------------------|------------|----------------------------------|------------|---------------|------------|-----------------------|------------|-----------|------------|--------------------------|------------|-----------|------------|
|                                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Revenues from unaffiliated customers:            |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Sale of gas                                      |       | $                                 | 2,767      |                             | $          | 6,158         |       | $                     | 1,808,586  |      | $          | 1,147                    |       | $         | —     |   | $ | — |   | $ | 1,818,658 |   |
| Sale of natural gas liquids                      |       | (556                              | )          | —                           |       | 329,968       |       | —                |       | —    |       | —                   |       | 329,412   |       |
| Equity hedges:                                   |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Residue                                          |       | 249                               |       | 3,441                            |       | —        |       | —                |       | —    |       | —                   |       | 3,690     |       |
| Liquids                                          |       | (10,012                           | )          | —                           |       | —        |       | —                |       | —    |       | —                   |       | (10,012   | )          |
| Gathering, processing and transportation revenue |       | 61,311                            |       | —                           |       | —        |       | 5,008                 |       | —    |       | —                   |       | 66,319    |       |
| Total revenues from unaffiliated customers:      |       | 53,759                            |       | 9,599                            |       | 2,138,554     |       | 6,155                 |       | —    |       | —                   |       | 2,208,067 |       |
|                                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Inter-segment sales                              |       | 766,734                           |       | 178,903                          |       | 40,202        |       | 10,705                |       | —    |       | (996,544                 | )          | —    |       |
| Price risk management activities                 |       | (56                               | )          | —                           |       | (11,557       | )          | —                |       | —    |       | —                   |       | (11,613   | )          |
| Interest Income                                  |       | —                            |       | 4                                |       | —        |       | 1                     |       | 13,802    |       | (13,807                  | )          | —    |       |
| Other, net                                       |       | 924                               |       | 10                               |       | (37           | )          | 49                    |       | 1,797     |       | —                   |       | 2,743     |       |
| Total revenues                                   |       | 821,361                           |       | 188,516                          |       | 2,167,162     |       | 16,910                |       | 15,599    |       | (1,010,351               | )          | 2,199,197 |       |
|                                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Product purchases                                |       | 638,467                           |       | 1,568                            |       | 2,170,903     |       | 3,822                 |       | —    |       | (969,478                 | )          | 1,845,282 |       |
| Plant and transportation operating expense       |       | 65,264                            |       | 77                               |       | (168          | )          | 5,420                 |       | —    |       | (2,428                   | )          | 68,165    |       |
| Oil and gas exploration and production expense   |       | —                            |       | 80,053                           |       | —        |       | —                |       | —    |       | (24,621                  | )          | 55,432    |       |
| (Earnings) from equity investments               |       | (5,244                            | )          |                             |       |          |       |                  |       |      |       |                     |       | (5,244    | )          |
| Segment operating profit                         |       | 122,874                           |       | 106,818                          |       | (3,573        | )          | 7,668                 |       | 15,599    |       | (13,824                  | )          | 235,562   |       |
|                                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Depreciation, depletion and amortization         |       | 27,981                            |       | 32,111                           |       | 87            |       | 1,239                 |       | 5,595     |       | —                   |       | 67,013    |       |
| Selling and administrative expense               |       | —                            |       | —                           |       | —        |       | —                |       | 37,542    |       | (36                      | )          | 37,506    |       |
| (Gain) loss from sale of assets                  |       | 224                               |       | (414                             | )          | —        |       | —                |       | 300       |       | 1,299                    |       | 1,409     |       |
| Loss from early extinguishment of debt           |       | —                            |       | —                           |       | —        |       | —                |       | 10,662    |       | —                   |       | 10,662    |       |
| Interest expense                                 |       | —                            |       | 41                               |       | 292           |       | (224                  | )          | 28,763    |       | (13,807                  | )          | 15,065    |       |
| Income before tax                                |       | $                                 | 94,669     |                             | $          | 75,080        |       | $                     | (3,952     | )         | $          | 6,653                    |       | $         | (67,263    | ) | $ | (1,280 | ) | $ | 103,907 |   |
|                                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Identifiable assets:                             |       |                              |       |                             |       |          |       |                  |       |      |       |                     |       |      |       |
| Equity investments                               |       | 38,021                            |       | —                           |       | —        |       | 3,822                 |       | 698,127   |       | (701,949                 | )          | 38,021    |       |
| Property and equipment                           |       | 641,898                           |       | 354,044                          |       | 18            |       | 37,226                |       | 52,986    |       | —                   |       | 1,086,172 |       |
| Other allocated assets                           |       | 6,214                             |       | 5,059                            |       | 36,228        |       | 24,598                |       | 385,054   |       | (52,446                  | )          | 404,707   |       |
| Total identifiable assets                        |       | 686,133                           |       | 359,103                          |       | 36,246        |       | 65,646                |       | 1,136,167 |       | (754,395                 | )          | 1,528,900 |       |

 

***NOTE 5 - 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, whileadmitting no liability, we entered into a Stipulation and Agreement ofSettlement with the plaintiffs for $5.9 million and accrued the liability inthe second quarter of 2005.  Thissettlement was approved by the court and was paid in October 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 defendantsin litigation filed on September 30, 1997, in 72 separate actions filed byMr. Grynberg on behalf of the federal government.  The allegations made by Mr. Grynberg arethat established gas measurement and royalty calculation practices improperlydeprived the federal government of appropriate natural gas royalties andviolate 31U.S.C. 3729(a)(7) of the False

 

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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.

 

***J.P. Morgan Trust Company, NationalAssociation, in its Capacity as Trustee of the FI Liquidating Trust v. OneokInc. et al., United States District Court, for the District of Kansas, Case No. 05-2389CM. ***On October 17,2005, the plaintiff, in its capacity as the liquidating trustee of thesuccessor in interest to Farmland Industries, Inc., filed an amendedcomplaint, joining us and other defendants to this action.  The complaint claims that the defendantsviolated the Kansas Restraint of Trade Act by reporting allegedly “misleadingor knowingly inaccurate reports concerning trade information” to tradepublications that compile and publish indices of natural gas prices for naturalgas trading hubs throughout the United States. The complaint asserts that these alleged activities had the effect ofincreasing prices charged by the defendants for natural gas and preventing fulland free competition. The plaintiff seeks to recover damages in the amount ofthe full consideration of its purchases of natural gas during the time periodfrom January 1, 2000 through December 31, 2001, together with itscosts of litigation including attorney’s fees. We believe that the claims are without merit and intend to vigorouslycontest the allegations in this case.

 

***Learjet, Inc., Cross Oil Refining &Marketing, Inc. Topeka Unified School District 501, on Behalf ofThemselves and All Other Similarly Situated Direct Purchasers of Natural Gas inthe State of Kansas v. Oneok, Inc. et al, In the District Court ofWyandotte County, Kansas, Civil Action No. 05-CV-1500.***  On November 4, 2005, the plaintiffs, onbehalf of themselves and all others similarly situated, filed an amendedPetition for Damages, joining us and other defendants to this action.  The Petition claims that the defendantsviolated the Kansas Restraint of Trade Act by reporting allegedly “misleadingor knowingly inaccurate reports concerning trade information” to tradepublications that compile and publish indices of natural gas prices for naturalgas trading hubs throughout the United States. The complaint asserts that the allegedly anticompetitive effect of thedefendant’s actions was to artificially inflate the prices paid by theplaintiffs for natural gas. The plaintiffs are bringing the action as a classaction on behalf of all persons and entities in Kansas who made directpurchases of natural gas, for their own use and or consumption, during the timeperiod from January 1, 2000 through October 31, 2002.  The plaintiffs are seeking judgment for thefull consideration of their purchases of natural gas purchased during such timeperiod, together with costs of litigation including attorney’s fees.  We believe that the claims are without meritand intend to vigorously contest the allegations in this case.

 

***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.

 

***NOTE 6 - 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.

 

**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 or the effect this statement will haveon our financial position, results of operations or cash flows.

 

**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

 

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beginning after June 15, 2005.  SFAS No. 153 amends APB Opinion No. 29,*Accounting for Nonmonetary Transactions*.  The guidance in APB Opinion No. 29 isbased on the principle that exchanges of nonmonetary assets should be measuredbased on the fair value of the assets exchanged but included certain exceptionsto that principle.  SFAS No. 153amends APB Opinion No. 29 to eliminate the exception for nonmonetaryexchanges of similar productive assets and replaces it with a general exceptionfor exchanges of nonmonetary assets that do not have commercial substance.  A nonmonetary exchange has commercialsubstance if the future cash flows of the entity are expected to changesignificantly as a result of the exchange. We adopted SFAS No. 153 on July 1, 2005, and the adoption ofthis pronouncement had no effect on our results of operations, financialposition or cash flows.

 

**EITF No. 04-13.  **At its September 2005meeting, the Emerging Issues Task Force, or EITF, of the FASB approved Issue No. 04-13, “*Accounting for Purchases and Salesof 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.  EITF 04-13 requires two or more exchangetransactions involving inventory with the same counterparty that are enteredinto in contemplation of one another should be combined for the purposes ofevaluating the effect of APB Opinion No. 29, “Accounting for NonmonetaryTransactions”.

 

Inorder to minimize transportation costs or make product available at a locationof our customer’s preference, from time to time, we will enter intoarrangements to buy product from a party at one location and arrange to sell alike quantity of product to this same party at another location.  In accordance with EITF 04-13, these transactionswill be required to be reported on a sales net of purchases basis.  This EITF is effective for transactionsentered into or modified after March 15, 2006.  To the extent transactions are required to benetted, it will result in a reduction of revenues and costs by an equal amount,but will have no impact on net income or cash flows.

 

Inaccordance with EITF 03-11, we recordrevenue on these transactions on a gross basis versus sales net of purchasesbasis because we obtain title to the product that we buy, bear the risk ofloss, credit and performance exposure on these transactions, and take physicaldelivery of the product.  For thequarters ended September 30, 2005 and 2004, we recorded revenues of $42.3million and $18.4 million, respectively, and product purchases of $41.5 millionand $19.2 million, respectively, for transactions which were entered intoconcurrently and with the intent to buy and sell like quantities with the samecounterparty at different locations and at market prices at those locations.  For the nine months ended September 30,2005 and 2004, we recorded revenues of $105.6 million and $67.8 million,respectively, and product purchases of $99.0 million and $63.7 million,respectively, for these types of transactions.

 

**FASB Interpretation No. 47. **FASB Interpretation No. 47,“*Accounting for Conditional Asset RetirementObligations, an interpretation of FASB Statement No. 143*”, orFIN 47, was issued in March 2005 and is effective in fiscal periods endingafter December 15, 2005.  FIN 47clarifies the term “conditional asset retirement obligation” as used in FASBStatement 143, “*Accounting for AssetRetirement Obligations*”. Conditional asset retirement obligations as used in FASB Statement 143refers to a legal obligation to perform an asset retirement activity in whichthe timing and (or) method of settlement are conditional on a future event thatmay or may not be within the control of the entity. The obligation to performan asset retirement activity is unconditional even though uncertainty existsabout the timing and (or) method of settlement. Accordingly, an entity isrequired to recognize a liability for the fair value of a conditional assetretirement obligation if the fair value of the liability can be reasonablyestimated. When sufficient information exists, uncertainty about the timing and(or) method of settlement should be factored into the measurement of theliability. We will adopt this interpretation as required and do not expect thepronouncement to have a material impact on our results of operation, financialposition or cash flows.

 

**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,Reporting Accounting Changes in Interim Financial Statements*.” ThisStatement requires retrospective application to prior periods’ financialstatements of a change in accounting principle. It applies both to voluntarychanges and to changes required by an accounting pronouncement if thepronouncement does not include specific transition provisions. APB 20previously required that most voluntary changes in accounting principles berecognized by recording the cumulative effect of a change in accountingprinciple. SFAS 154 is effective for fiscal years beginning after December 15,2005. We plan to adopt this statement on January 1, 2006 and it is notexpected to have a material effect on the financial statements upon adoption.

 

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***NOTE 7 – SUBSEQUENT EVENT- AMENDMENT AND RESTATEMENT OFREVOLVING CREDIT FACILITY.***

 

InNovember 2005, we amended and restated our existing revolving credit facility.  The amended and restated facility is a five-year,$700 million revolving credit facility maturing in November 2010.  Loans made under this facility aresecured by a pledge of the capital stock of our significant subsidiaries, andthese subsidiaries also guarantee the borrowings under the facility.  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.  The borrowings under this creditfacility bear interest at Eurodollar rates or a base rate, as requested by us,plus an applicable percentage based on our debt to capitalization ratio.  The base rate is the agent’s published primerate.  We also pay a quarterly commitmentfee on undrawn amounts ranging between 0.10% and 0.30%, depending on our debtto capitalization ratio.  This fee ispaid on unused amounts of the commitment. As of November 30, 2005, the interest rate payable on borrowingsunder this facility was approximately 5.18% per year.

 

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

 

Thefollowing discussion and analysis relates to factors that have affected ourconsolidated financial condition and results of operations for the three and ninemonths ended September 30, 2005 and 2004. Certain prior year amounts have been reclassified to conform to thepresentation used in 2005.  You shouldalso refer to our interim consolidated financial statements and notes theretoincluded elsewhere in this document. This section, as well as other sections in this Form 10-Q, contain “forward-lookingstatements” within the meaning of the Private Securities Litigation Reform Actof 1995, which can be identified by the use of forward-looking terminology, suchas “may,” “intend,” “will,” “expect,” “anticipate,” “estimate,” or “continue”or the negative thereof or other variations thereon or comparableterminology.  In addition to theimportant factors referred to herein, numerous factors affecting the gas processingindustry generally and in the specific markets for gas and NGLs in which weoperate could cause actual results to differ materially from those in suchforward-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 management and our audit committee have completed areview of the accounting treatment of our gas storage and gas transportationcontracts and determined that these contracts do not meet the definition of aderivative.  Specifically, after adetailed review of the contracts and the market for those contracts, wesubsequently determined that these contracts do not meet the definition of aderivative as: (i) the market for these types of contracts is notsufficiently liquid for us to receive fair value in a ready market and (ii) ifany contract is assigned, there is no assurance that we will be relieved of ourrights and obligations under that contract.

 

Historically,the non-cash mark-to-market valuation of the gas storage and transportationcontracts which, prior to the restatement, were considered to be derivativeseffectively 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 nine months ending September 30, 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 (amounts in thousands, except per share amounts):

 
| ** **                            | ** ** | **Three months ending**     | ** ** | **Nine months ending**      | ** ** |
|---------------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| ** **                            | ** ** | **September 30, 2004** | ** ** | **September 30, 2004** | ** ** |
| ** **                            | ** ** | **As**                      | ** ** | **As**                      | ** ** | **As** | ** ** | **As** | ** ** |
| ** **                            | ** ** | **Reported**                | ** ** | **Restated**                | ** ** | **Reported** | ** ** | **Restated** | ** ** |
| Total revenues                        |       | $                           | 718,255    |                        | $          | 693,679 |   | $ | 2,215,774 |   | $ | 2,199,197 |   |
|                                  |       |                        |       |                        |       |   |   |   |   |
| Income before  taxes                  |       | 55,511                      |       | 30,935                      |       | 120,484 |   | 103,907 |   |
| Net income                            |       | 35,118                      |       | 19,465                      |       | 78,181 |   | 67,548 |   |
| Earnings per  share-assuming dilution |       | 0.47                        |       | 0.26                        |       | 1.06 |   | 0.91 |   |
| Cash flow from  operating activities  |       | $                           | 38,546     |                        | $          | 38,546 |   | $ | 126,678 |   | $ | 126,678 |   |

 

***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, and the San Juan Basin in New Mexico; and our midstreamoperations in west Texas and Oklahoma. Our long-term business plan is to increase stockholder value by: (i) doublingproven natural gas reserves and equity production of natural gas from the levelsachieved 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

 

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of Mexico, are mature andare in production decline.  Our efforts,while concentrated in the Rocky Mountain area, extend into a variety of diverseunconventional gas plays, where there are estimated to be large quantities ofundeveloped gas.   We are well positionedfor future production growth with a large inventory of undeveloped drillinglocations in the Powder River, the Greater Green River and San Juan Basins tomeet 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.

 

Ouroperations are 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 relatively low geologic risk, and are multi-year development projects.  These provide us with the opportunity to steadilyincrease our production volume over time at reasonable operating and lowfinding and development costs.  In thethird quarter of 2005, our average production sold was 177 MMcfe per day, whichis a 14% increase over the daily average production volume sold in the thirdquarter of 2004.

 

Wecontinue to seek to add additional upstream core projects that are focused onunconventional gas reservoirs.  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.  Whilewe have historically focused on the Rocky Mountain region, 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 and participate in drillingoperations in the Western Canadian Sedimentary Basin.  Overall, at September 30, 2005, we haveacquired the drilling rights on approximately 1.6 million net acres in variousRocky Mountain and other basins and continue to expand our leasehold positions.

 

***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 ourcustomers.  Our expertise in gathering,processing and treating operations can enhance the economics of developing newupstream projects.

 

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 third quarter of 2005 increased 7% as compared to thesame period in 2004 and averaged a total of 1.5 Bcf per day.

 

***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

 

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enhance the valuereceived for our equity volumes of natural gas. This goal is achieved through the use of hedges on the production of ourequity natural gas and NGLs and through the use of firm 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 andnine months ended September 30, 2005 compared to the three and nine monthsended September 30, 2004**

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

 
| ** **                                          | ** ** | **Three Months Ended** | ** ** | ** **   | ** ** | **Nine Months Ended**  | ** ** | ** ** | ** ** |
|-----------------------------------------------------|------------|------------------------|------------|--------------|------------|------------------------|------------|------------|------------|
| ** **                                          | ** ** | **September 30,** | ** ** | ** **   | ** ** | **September 30,** | ** ** | ** ** | ** ** |
| ** **                                          | ** ** | ** **             | ** ** | **2004**     | ** ** | **Percent**            | ** ** | ** ** | ** ** | **2004** | ** ** | **Percent** | ** ** |
| ** **                                          | ** ** | **2005**               | ** ** | **Restated** | ** ** | **Change**             | ** ** | **2005**   | ** ** | **Restated** | ** ** | **Change** | ** ** |
| ** **                                          | ** ** | ** **             | ** ** | ** **   | ** ** | ** **             | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Financial results:**                              |       |                   |       |         |       |                   |       |       |       |   |   |   |   |
| Revenues                                            |       | $                      | 961,410    |         | $          | 693,679                |       | 39         |       | $ | 2,663,543 |   | $ | 2,199,197 |   | 21 |   |
| Net income                                          |       | 10,735                 |       | 19,465       |       | (45                    | )          | 68,070     |       | 67,548 |   | 1 |   |
| Earnings per share of common stock                  |       | 0.14                   |       | 0.26         |       | (46                    | )          | 0.92       |       | 0.93 |   | (1 | ) |
| Earnings per share of common stock - diluted        |       | 0.14                   |       | 0.26         |       | (46                    | )          | 0.90       |       | 0.91 |   | (1 | ) |
| Net cash provided by (used in) operating activities |       | (10,434                | )          | 34,332       |       | (130                   | )          | 149,668    |       | 126,678 |   | 18 |   |
| Net cash (used in) investing activities             |       | (109,630               | )          | (66,561      | )          | (64                    | )          | (300,718   | )          | (144,885 | ) | (108 | ) |
| Net cash (used in) provided by financing activities |       | $                      | 133,559    |         | $          | 32,061                 |       | 317        |       | $ | 170,193 |   | $ | (5,190 | ) | 3379 |   |
| ** **                                          | ** ** | ** **             | ** ** | ** **   | ** ** | ** **             | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Operating data:**                                 |       |                   |       |         |       |                   |       |       |       |   |   |   |   |
| Average gas sales (MMcf/D)                          |       | 1,152                  |       | 1,130        |       | 2                      |       | 1,205      |       | 1,229 |   | (2 | ) |
| Average NGL sales (MGal/D)                          |       | 2,009                  |       | 1,741        |       | 15                     |       | 1,883      |       | 1,665 |   | 13 |   |
| Average gas prices ($/Mcf)                          |       | $                      | 7.72       |         | $          | 5.38                   |       | 43         |       | $ | 6.65 |   | $ | 5.39 |   | 23 |   |
| Average NGL prices ($/Gal)                          |       | $                      | 1.04       |         | $          | 0.78                   |       | 33         |       | $ | 0.92 |   | $ | 0.70 |   | 31 |   |

 

Net income decreased $8.7 million for the three monthsended September 30, 2005, compared to the same period in 2004.  The decrease in net income was primarilyattributable to the non-cash mark-to-market of our risk management activities,which more than offset higher production of equity gas volumes and highercommodity prices in the third quarter of 2005.

 

Net income increased $522,000 for the nine months ended September 30,2005, compared to the same period in 2004. This increase was primarilyattributable to higher production of equity gas volumes and highercommodity prices that were substantially offset by the non-cash mark-to-marketof our risk management activities.  Inthe first nine months of 2005, we incurred an after-tax charge of $3.8 millionrecorded in connection with a settlement of litigation.   The 2004 period included an after-tax chargeassociated with a settlement with the CFTC of $7.0 million, and an after-tax charge associated with the earlyextinguishment of long-term debt of $6.7 million.  Partiallyoffsetting these items in the 2004 period was the cumulative effect of a changein accounting principle.  Effective as ofJanuary 1, 2004, we revised our depreciation and depletion methodology forour oil and gas properties.  This changein accounting principle resulted in a cumulative reduction of depreciation forperiods prior to 2004 of $4.7 million, net of tax, in 2004.

 

Revenuesfrom the sale of gas increased $260.3 million to $821.5 million for the three monthsended September 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 September 30,2005 compared to the same period in 2004. Average gas prices realized by us increased $2.34 per Mcf to $7.72 perMcf for the quarter ended September 30, 2005 compared to the same periodin 2004.  Included in the realized gasprice was approximately $857,000 of gains recognized in the three months ended September 30,2005 related to futures positions on equity gas volumes.  We have entered into additional futurespositions for our equity gas for the remainder of 2005 and in 2006.  See further discussion in “Item 3.Quantitative and Qualitative Disclosures About Market Risk.”  Average gas sales volumes increased slightlyto 1,152 MMcf per day for the quarter ended September 30, 2005 compared tothe same period in 2004.

 

23

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Revenuesfrom the sale of gas increased $373.4 million to $2,195.8 million for the ninemonths ended September 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 nine months ended September 30,2005, compared to the same period in 2004. Average gas prices realized by us increased $1.26 per Mcf to $6.65 perMcf for the nine months ended September 30, 2005 compared to the sameperiod in 2004.  Included in the realizedgas price were approximately $2.6 million of gains recognized in the ninemonths ended September 30, 2005 related to futures positions on equity gasvolumes.  We have entered into additionalfutures positions for our equity gas for the remainder of 2005 and in2006.  See further discussion in “Item 3.Quantitative and Qualitative Disclosures About Market Risk.”  Average gas sales volumes decreased slightlyto 1,205 MMcf per day for the nine months ended September 30, 2005compared to the same period in 2004.

 

Revenuesfrom the sale of NGLs increased $67.1 million to $191.6 million for the threemonths ended September 30, 2005 compared to the same period in 2004.  This is due to a significant increase inproduct prices and an increase in sales volumes.  Average NGL prices realized by us increased$0.26 per gallon to $1.04 per gallon for the three months ended September 30,2005 compared to the same period in 2004. Included in the realized NGL price were approximately $3.5 million oflosses recognized in the three months ended September 30, 2005 related tofutures positions on equity NGL volumes. We have entered into additional futures positions for our equity NGLproduction for the remainder of 2005 and in 2006.  See further discussion in “Item 3.Quantitative and Qualitative Disclosures About Market Risk.”  Average NGL sales volumes increased 268 MGalper day to 2,009 MGal per day for the three months ended September 30,2005 compared 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 $154.6 million to $474.0 millionfor the nine months ended September 30, 2005 compared to the same periodin 2004.  This is primarily due to asignificant increase in product prices and, to a lesser extent, an increase insales volumes.  Average NGL pricesrealized by us increased $0.22 per gallon to $0.92 per gallon for the ninemonths ended September 30, 2005 compared to the same period in 2004.  Included in the realized NGL price wereapproximately $5.5 million of losses recognized in the nine months ended September 30,2005 related to futures positions on equity NGL volumes.  We have entered into additional futurespositions for our equity NGL production for the remainder of 2005 and in2006.  See further discussion in “Item 3.Quantitative and Qualitative Disclosures About Market Risk.”  Average NGL sales volumes increased 218 MGalper day to 1,883 MGal per day for the nine months ended September 30, 2005compared to the same period in 2004. This increase is due to the acquisition ofseveral facilities in February 2005.

 

Pricerisk management activities changed from ($17.6) million for the quarter ended September 30,2004 to ($79.9) million for the quarter ended September 30, 2005.  This change was due to the non-cashmark-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 the 2004quarter and the impact of those price changes on the fair value of the forwardsale derivatives for our gas in storage.

 

Pricerisk management activities changed from ($11.6) million for the nine months endedSeptember 30, 2004 to ($88.9) million for the nine months ended September 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 $249.1 million and $404.5 million for the quarter andnine months ended September 30, 2005, respectively, compared to the sameperiods in 2004.  These increases inproduct purchases were the result of higher product prices.  On a consolidated basis, combined productpurchases, as a percentage of sales of all products was 81% in the quarterended September 30, 2005 compared to 84% in the quarter ended September 30,2004.  Combined product purchases as apercentage of sales of all products decreased to 84% for the nine months ended September 30,2005 from 86% in 2004.  The reduction inthis percentage is primarily the result of an increase in revenues from thesale of equity production.

 

Plantand transportation operating expense increased by $7.1 million and $17.4million, respectively, for the three and nine months ended September 30,2005 compared to the same periods in 2004. The increase for the quarter and nine month periods ended September 30,2005 as compared to the same period in 2004 was substantially due to increasedfees paid for the use of third party gathering systems behind our facilities,property tax, labor and repairs and maintenance expenses and the October 2004and February 2005 asset acquisitions.

 

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Oiland gas exploration and production expense increased by $9.8 million and $21.8million, respectively, for the three and nine months ended September 30,2005 compared to the same periods in 2004. The increase for the quarter ended September 30, 2005 as comparedto the same period in 2004 was substantially due to increased production taxesand expenses associated with the San Juan properties acquired in October 2004.The increase for the nine months ended September 30, 2005 as compared tothe same 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$0.81 per Mcf and $0.82 per Mcf for the quarter and nine months ended September 30,2005, respectively and LOE in the Powder River Basin coal bed developmentaveraged $0.92 and $0.89 per Mcf in the quarter and nine months ended September 30,2005, respectively.  In the Powder RiverBasin, these represent increases of $0.16 and $0.11 per Mcf from the sameperiods in 2004.  The increase in LOE perMcf  in the Powder River Basin issubstantially due to higher water handling charges on dewatering wells inseveral new pilot areas that have no offsetting gas production as yet, contractlabor, and fuel and operating costs of wellhead blowers in the Powder RiverBasin as well as increased costs related to initiating operations of the SanJuan Basin production assets.  Weanticipate upward pressure on LOE in 2006 due to increased labor and supplycosts as well as increased use of water treatment facilities.

 

Depreciation, depletion and amortization, or DD&A,increased by $10.4 million and $25.3 million, respectively, for the three andnine months ended September 30, 2005 as compared to the same periods in 2004.  For the quarter ended September 30, 2005as compared to the same period in 2004, we had a $1.8 million increase inDD&A in our midstream operations primarily due to our expanding CBMgathering system in the Powder River Basin and the October 2004 acquisitionof additional midstream assets in the San Juan Basin, and a $8.2 millionincrease in DD&A in our upstream operations primarily due to our continueddevelopment in the Powder River Basin, downward revisions to reserves in thePowder River Basin based on the December 2004 reserve report, and our October 2004acquisition of producing properties in the San Juan Basin.  For the nine months ended September 30,2005 as compared to the same period in 2004, we had a $6.5 million increase inDD&A in our midstream operations and a $18.8 million increase in ourupstream operations primarily due to those items mentioned above.

 

Sellingand administrative expenses increased by $5.7 million and $8.5 million for thethree and nine months ended September 30, 2005 as compared to the sameperiod in 2004.   The increase in sellingand administrative expenses for the quarter ended September 30, 2005 ascompared to 2004 was primarily the result of increased administrative salariesand benefits, donations to the hurricane relief efforts, bad debt expense, andcompensation expense related to our restricted stock plan.  The increase in selling and administrativeexpenses for the nine months ended September 30, 2005 as compared to 2004was primarily the result of increased administrative salaries and benefits,insurance, audit expenses, donations to the hurricane relief efforts, bad debtexpense, and compensation expense related to our restricted stock plan.  Additionally, the nine months ended September 30,2005 included a charge of $5.9 million in connection with a settlement oflitigation and the nine months ended September 30, 2004 included a $7.0million charge for a settlement with the CFTC.

 

TheTotal provision for income taxes, as a percentage of Income before taxes was approximately35.9% and 36.2%, respectively, during the quarter and nine months ended September 30,2005 as compared to 36.7% and 39.0%, respectively, in same periods of2004.  The decrease in the percentage ofincome taxes in the nine-month periods is primarily due to the civil penaltypaid to the CFTC in 2004, which was non-deductible for tax purposes.

 

***Cash FlowInformation***

 

Cashflows from operating activities increased by $23.0 million in the first ninemonths of 2005 compared to the same period in 2004. This increase was primarilydue to the increase in net income, which was partially offset by margin callspaid in the 2005 period on financial sales of the gas in our storagepositions.  At September 30, 2005,we had a total of $110.7 million of margin posted with our counterparties forthese transactions.  The amount of marginposted has decreased to $53.8 million on November 7, 2005 and we willreceive these margin deposits back as these positions expire during the fourthquarter of 2005 and the first quarter of 2006, or as the commodity pricedeclines.

 

Cashflows used in investing activities increased by $155.8 million in the firstnine months 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 provided by financing activities increased by $175.4 million in the firstnine months of 2005 compared to the same period in 2004.  This increase was due to the utilization offunds provided by financing activities in 2005 to fund our capital investmentsand margin calls on financial sales of our storage positions.

 

25

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***Segment Information***

 

***GasGathering, Processing and Treating.***  The Gas Gathering, Processing and Treatingsegment realized segment-operating profit of $171.4 million for the nine monthsended September 30, 2005 compared to $122.9 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.  

 
| ** **                                                  | ** ** | **Quarter Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|-------------------------------------------------------------|------------|---------------------------------------|------------|-------------------------------------------|------------|
| ** **                                                  | ** ** | **2005**                              | ** ** | **2004**                                  | ** ** | **2005** | ** ** | **2004** | ** ** |
| Gross Margin ($/Mcf)  (1)                              |       | $                                     | 0.72       |                                      | $          | 0.55 |   | $ | 0.65 |   | $ | 0.52 |   |
| Segment Plant operating and transportation expense  ($/Mcf) |       | 0.22                                  |       | 0.18                                      |       | 0.21 |   | 0.18 |   |
| Net Margin ($/Mcf)                                          |       | $                                     | 0.50       |                                      | $          | 0.37 |   | $ | 0.44 |   | $ | 0.34 |   |
| Average gas volumes gathered (MMcf/D)                       |       |                                  | 1,490      |                                      |       | 1,389 |   |   | 1,414 |   |   | 1,361 |   |

 

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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-operating profitof $158.1 million for the nine months ended September 30, 2005 compared to$106.8 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 nine months of 2005, our production of natural gas ascompared to the same period in 2004 increased by 13% to 45.8 Bcfe.  The following table sets forth the averagesales price received for our oil and gas products in the quarter and ninemonths ended September 30, 2005 and 2004.

 
| ** **                                                   | ** ** | **Quarter Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|--------------------------------------------------------------|------------|---------------------------------------|------------|-------------------------------------------|------------|
| ** **                                                   | ** ** | **2005**                              | ** ** | **2004**                                  | ** ** | **2005** | ** ** | **2004** | ** ** |
| Average sales price: (1)                                     |       |                                  |       |                                      |       |   |   |   |   |
| Oil ($/Bbl)                                                  |       | $                                     | 52.91      |                                      | $          | 35.32 |   | $ | 48.22 |   | $ | 35.34 |   |
| Gas ($/Mcf),  excluding the effect of hedging positions |       | 6.46                                  |       | 4.53                                      |       | 5.59 |   | 4.50 |   |
| Gas ($/Mcf), including the effect of hedging  positions      |       | 6.50                                  |       | 4.55                                      |       | 5.64 |   | 4.59 |   |
|                                                         |       |                                  |       |                                      |       |   |   |   |   |
| Production and other costs:                                  |       |                                  |       |                                      |       |   |   |   |   |
| Lease operating expense ($/Mcfe)                             |       | 0.81                                  |       | 0.61                                      |       | 0.82 |   | 0.64 |   |
| Production tax expense ($/Mcfe)                              |       | 0.72                                  |       | 0.46                                      |       | 0.60 |   | 0.48 |   |
| Gathering and transportation expense ($/Mcfe)                |       |                                  |       |                                      |       |   |   |   |   |
| Inter-segment charges                                        |       | 0.60                                  |       | 0.63                                      |       | 0.57 |   | 0.60 |   |
| Third-party charges                                          |       | 0.19                                  |       | 0.15                                      |       | 0.21 |   | 0.14 |   |
| Other expenses ($/Mcfe)                                      |       | 0.02                                  |       | 0.03                                      |       | 0.02 |   | 0.02 |   |
| Total costs ($/Mcfe)                                         |       | $                                     | 2.34       |                                      | $          | 1.88 |   | $ | 2.22 |   | $ | 1.88 |   |

 

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(1)  The prices received for NGLs areincluded in the price received for gas.

 

***Marketing.***  The Marketing segment realizedsegment-operating profit of ($83.0) million for the nine months ended September 30,2005 compared to ($3.6) million in the same period of 2004.  The decrease was primarily due to non-cash mark-to-market losses from our pricerisk management activities related to future sales of gas utilizing our storageand 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 $9.3 million for the nine months ended September 30,2005 compared to $7.7 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 Note 6 of Notes to Consolidated FinancialStatements (Unaudited) in Item 1 of this Form 10-Q 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**

 

26

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#### **sources of liquidity and capital resources will beavailable for future development and acquisition projects, and we may berequired to seek additional or alternative financing sources.  Product prices, hedges of equity production,sales of inventory, the volume of natural gas processed by our facilities, thevolume of natural gas produced from our producing properties, the margin onthird-party product purchased for resale, as well as the timely collection ofour receivables and the availability of oil field services and supplies such asconcrete and steel pipe are all expected to have significant influences on ourfuture net cash provided by operating activities.  Additionally, our future growth will bedependent upon the success and timing of our exploration and productionactivities, obtaining additions to dedicated plant reserves, acquisitions, newproject development, marketing results, efficient operation of our facilitiesand our ability to obtain financing at favorable terms.**

#### ** **

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, none of which is within our control. There is noassurance that we will continue to be successful in replacing the dedicatedreserves processed at our facilities. Any prolonged reduction in prices for natural gas and NGLs may depressthe levels of exploration, development and production by third parties.  Lower levels of these activities could resultin a corresponding decline in the demand for our gathering, processing andtreating services.  A significantreduction in any of these activities could have a material adverse effect onour financial condition, results of operations and cash flows.

 

In the third quarter of 2005, the Gulf Coast ofthe United States was impacted by two major hurricanes.  These storms resulted in the curtailment ofnatural gas and oil production from the Gulf of Mexico, and the operations ofmajor refineries and gas processing facilities in Texas, Louisiana andMississippi.  Our operations did notsustain any physical damage from these hurricanes, and our liquidity was notmaterially impacted as our counterparties and customers continued to maketimely payments.  However, in September 2005,one of our customers, a utility serving the New Orleans area, filed forbankruptcy protection under Chapter 11 of the Bankruptcy Code.  At the time of the bankruptcy filing, we hadan outstanding account receivable from this utility of $4.1 million.  In the third quarter of 2005, we reserved$800,000 against this amount, which represents our best estimate of the currentmarket value of this receivable.  Also asa result of these storms, natural gas and crude oil prices have increasedsubstantially resulting in significant margin calls to us primarily fromfinancial instruments entered into by us to pre-sell our natural gas and NGLstorage positions.  At September 30,2005, we had margin deposits posted of $110.7 million.  The amount of margin posted has decreased to$53.8 million on November 7, 2005, and we will receive this margin back asthese positions expire during the fourth quarter of 2005 and the first quarterof 2006 or as commodity prices decline.

 

Even with the impact of, and the marketuncertainty caused by, these storms, we believe that the amounts available tobe borrowed under our financing facilities, together with the net cash providedby operating 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 thesealternatives.  While we believe that wewould be able to secure additional financing, if required, we can provide noassurance that we will be able to do so or as to the terms of any additionalfinancing.

 

In September 2005, our board of directorsannounced its intent to increase our annual dividend on common stock from $0.20per share to $0.30 per share.  Thisincrease, if declared, will be effective beginning with the dividend paid toholders of record on December 31, 2005. We expect our dividends to total approximately $22.5 million in 2006 andthat they will be funded with net cash provided by operating activities.

 

27

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

 
| **Sources of funds:**                                            |   |    |      |
|------------------------------------------------------------------|--------|---------|-----------|
| Borrowings under our revolving credit facility                   |   | $       | 3,097,865 |   |
| Borrowings under our master shelf agreement                      |   | 25,000  |      |
| Proceeds from the dispositions of property and  equipment        |   | 1,856   |      |
| Net cash provided by operating activities                        |   | 149,668 |      |
| Distributions from equity investments                            |   | 897     |      |
| Change in outstanding checks                                     |   | 26,725  |      |
| Proceeds from exercise of common stock options                   |   | 12,134  |      |
| Total sources of funds                                           |   | $       | 3,314,145 |   |
| **Uses of  funds:**                                              |   |    |      |
| Payments related to long-term debt (including debt  issue costs) |   | $       | 2,945,404 |   |
| Capital expenditures                                             |   | 301,147 |      |
| Payments made under our master shelf agreement                   |   | 35,000  |      |
| Contributions to equity investments                              |   | 2,324   |      |
| Common dividends paid                                            |   | 11,127  |      |
| Total uses of funds                                              |   | $       | 3,295,002 |   |

 

***Capital Investment Program.***  We currently anticipate capital expendituresin 2005 of approximately $419.1 million.  Overall, capital expenditures in the Powder River Basin CBM developmentand in the Greater Green River Basin operations represent 36% and 30%,respectively, of the total 2005 budget. Due to drilling and regulatory uncertainties that are beyond ourcontrol, we can make no assurance that our capital budget for 2005 will notchange or that we will actually incur this level of capital expenditures.  This budget may be increased to provide foracquisitions if approved by our board of directors.

 

The2005 capital budget and our capital expenditures during the nine months ended September 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)     |       | $                        | 169.4      |                                   | $          | 107.8 |   |
| Exploration and  production and lease acquisition activities |       | 210.4                    |       | 161.6                                  |       |
| Acquisition of  Greater Green River Basin midstream assets   |       | 28.0                     |       | 28.0                                   |       |
| Information  technology and other items                      |       | 3.0                      |       | 2.9                                    |       |
| Capitalized  interest and overhead                           |       | 8.3                      |       | 9.4                                    |       |
| Total Capital Expenditures                                   |       | $                        | 419.1      |                                   | $          | 309.7 |   |

 

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(1) Includes $13.7million budgeted in 2005 and $7.0 million expended in the nine months ended September 30,2005 for maintaining existing facilities.

 

***Contractual Commitmentsand Obligations***

 

##### ***Contractual Cash Obligations. ***Asummary of our contractual commitments and cash obligations as of September 30,2005 is as follows (dollars in thousands):

 
| ** **                                 | ** ** | ** **             | ** ** | **Payments by Period** | ** ** |
|--------------------------------------------|------------|------------------------|------------|------------------------|------------|
| **Type of Obligation**                     | ** ** | **Total  Obligations** | ** ** | **Due in  2005**       | ** ** | **Due in  2006 – 2007** | ** ** | **Due in  2008 – 2009** | ** ** | **Due  Thereafter** | ** ** |
| Guarantee of  Fort Union Project Financing |       | $                      | 4,555      |                   | $          | 246 |   | $ | 2,146 |   | $ | 2,163 |   | $ | — |   |
| Operating Leases                           |       | 76,576                 |       | 4,508                  |       | 33,568 |   | 25,734 |   | 12,766 |   |
| Firm  Transportation Capacity Agreements   |       | 254,976                |       | 10,809                 |       | 86,117 |   | 75,131 |   | 82,919 |   |
| Firm Storage  Capacity Agreements          |       | 29,255                 |       | 2,695                  |       | 12,720 |   | 5,041 |   | 8,799 |   |
| Long-term Debt                             |       | 524,500                |       | —                 |       | 20,000 |   | 379,500 |   | 125,000 |   |
| Interest on  Long-term Debt (1)            |       | 121,560                |       | 7,105                  |       | 54,967 |   | 43,597 |   | 15,891 |   |
| Total  Contractual Cash Obligations        |       | $                      | 1,011,422  |                   | $          | 25,363 |   | $ | 209,518 |   | $ | 531,166 |   | $ | 245,375 |   |

 

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(1)The interest rateassumed on the revolving credit facility at September 30, 2005 is 5.1% perannum.

 

28

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***Guarantee of Fort Union Project Financing.***   We own a 15% equity interest in Fort UnionGas Gathering, L.L.C., or Fort Union, and are the construction manager andfield operator.  Fort Union gathers andtreats natural gas in the Powder River Basin in northeast Wyoming.  Initial construction and any expansions ofthe gathering header and treating system have been project financed by FortUnion.  This debt is amortizing on anannual basis with the final payment due in 2009.   Our requirement to fund under this guaranteewould be reduced by the value of assets held by Fort Union.  This guarantee is not reflected on ourConsolidated Balance Sheet.

 

***Operating Leases. **** *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 leases havereturn or fair market purchase options available at various times during thelease.   If we were to exercise thepurchase options on all the leased compression equipment, these purchaseoptions would require the capital expenditure of approximately $45.0 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 generallyrequire the payment of fixed monthly fees regardless of the quantity of gasthat flows under a particular agreement. These agreements are not reflected on our Consolidated Balance Sheet.

 

At September 30,2005, the fixed fees associated with our existing contracts for firmtransportation capacity during 2005 will average approximately $0.15 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 September 30,2005, we had contracts in place for approximately 17.6 Bcf of storage capacityat various third-party facilities.  Firmstorage agreements generally require the payment of fixed monthly feesregardless of the quantity of gas that is in storage under a particularagreement.  Of the total storage 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 September 30,2005 had an average term of 32 months. At September 30, 2005, we held gas in our contracted storagefacilities and in imbalances of approximately 19.5 Bcf at an average cost of$6.89 perMcf compared to 19.6 Bcf at an average cost of $5.39 per Mcf at September 30,2004.  These positions are for storagewithdrawals within the next nine months. At the time we place product into storage, we contract for the sale ofthat product, physically or financially, and do not speculate on the futurevalue of the product.

 

At September 30,2005, we held NGLs in line pack and in storage at various third-partyfacilities of 3,045 MGal, consisting primarily of propane and ethane, at anaverage cost of $0.41 per gallon compared to 2,877 MGal at an average cost of$0.32 per gallon at September 30, 2004.

 

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

#### ** **

***Revolving Credit Facility. ***At September 30, 2005, the commitmentunder the revolving credit facility was $500 million and matured in June 2009.  At September 30, 2005, $379.5 millionwas outstanding under this facility.  Loans made under this facility are secured by a pledge of the capitalstock of our significant subsidiaries, and these subsidiaries also guaranteethe borrowings under the facility.  In October 2005,we increased the commitment under the revolving credit facility to $580 millionto assure adequate liquidity in a rising price environment.

 

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

 

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pay a quarterlycommitment fee on undrawn amounts ranging between 0.20% and 0.375%, dependingon our debt to capitalization ratio. This fee is paid on unused amounts of the commitment.  As of September 30, 2005, the interestrate payable on borrowings under this facility was approximately 5.1% 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.

 

InNovember 2005, we amended and restated our existing revolving credit facility.  The amended and restated facility is afive-year, $700 million revolving credit facility maturing in November 2010.  The covenants under the amended facilityremained the same as the existing facility and our borrowing rate was reducedby approximately 50 basis points.

 

***Master Shelf Agreement. ***Amountsoutstanding under our master shelf agreement at September 30, 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 than 55% andmaintaining a quarterly test of EBITDA, as defined in our master shelfagreement, to interest for the last four quarters in excess of 3.0 to 1.0.

 

***Upstream Operations***

 

A vital aspect of ourlong-term business plan is to double proven natural gas reserves and equityproduction of natural gas from the level at December 31, 2001 over afive-year period.  In order to achievethis goal, we will focus on continued development of our leasehold positions inthe Powder River Basin CBM development, the Greater Green River Basin, the SanJuan Basin, and the Sand Wash Basin. Each of our existing upstream projects isfully integrated with our midstream operations. In other words, in each of these areas, we provide the gathering,compression, processing, marketing or transportation services for both our ownproduction and for third-party operators. Additionally, we are actively pursuing new exploration, development andproducing property acquisition opportunities.

 

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

 
| ** **              | ** ** | **As of September 30, 2005** | ** ** | ** **                 | ** ** |
|-------------------------|------------|-----------------------------------|------------|----------------------------|------------|
| **Production Area**     | ** ** | **Gross Acres  Under Lease**      | ** ** | **Net Acres  Under Lease** | ** ** | **Gross  Productive  Gas Wells** | ** ** | **Net  Productive  Gas Wells** | ** ** | **Net  Production**** Sold  (Mmcfe per day)*** | ** ** |
| Powder River  Basin     |       | 1,035,000                         |       | 528,000                    |       | 4,896 |   | 2,331 |   | 114 |   |
| Jonah/Pinedale  Field   |       | 165,000                           |       | 46,000                     |       | 323 |   | 36 |   | 38 |   |
| San Juan Basin          |       | 28,000                            |       | 27,000                     |       | 167 |   | 147 |   | 11 |   |
| Sand Wash Basin         |       | 120,000                           |       | 113,000                    |       | 21 |   | 21 |   | 5 |   |
| Denver-Julesburg  Basin |       | 393,000                           |       | 339,000                    |       | 9 |   | 9 |   | — |   |
| Canada                  |       | 14,000                            |       | 13,000                     |       | 2 |   | 2 |   | — |   |
| Other                   |       | 625,000                           |       | 546,000                    |       | 13 |   | 3 |   | 1 |   |
| Total                   |       | 2,380,000                         |       | 1,612,000                  |       | 5,431 |   | 2,549 |   | 169 |   |

 

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* Average for the ninemonths ended September 30, 2005.

 

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***Drilling Results.* **The following table sets forth the numberof wells we drilled during the nine months ended September 30, 2005 and2004 in each of our major producing areas. This information should not be considered indicative of futureperformance, nor should it be assumed that there is necessarily any correlationbetween the number of productive wells drilled, quantities of reserves found oreconomic value.

 
| ** **              | ** ** | ** **               | ** ** | **Nine Months Ended September 30,** | ** ** |
|-------------------------|------------|--------------------------|------------|------------------------------------------|------------|
| ** **              | ** ** | ** **               | ** ** | **2005**                                 | ** ** | **2004** | ** ** |
| **Production Area**     | ** ** | **Type of Well Drilled** | ** ** | **Gross**                                | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Powder River  Basin CBM |       | Productive               |       | 703                                      |       | 343 |   | 512 |   | 246 |   |
|                    |       |                     |       |                                     |       |   |   |   |   |   |   |
| Jonah/Pinedale  Field   |       | Productive               |       | 70                                       |       | 7 |   | 50 |   | 5 |   |
|                    |       | Dry exploratory          |       | 1                                        |       | 0 |   | 0 |   | 0 |   |
|                    |       |                     |       |                                     |       |   |   |   |   |   |   |
| San Juan Basin          |       | Productive               |       | 30                                       |       | 28 |   | 0 |   | 0 |   |
|                    |       |                     |       |                                     |       |   |   |   |   |   |   |
| Sand Wash Basin         |       | Productive               |       | 5                                        |       | 5 |   | 5 |   | 5 |   |
|                    |       | Dry exploratory          |       | 1                                        |       | 1 |   | 1 |   | 1 |   |
|                    |       |                     |       |                                     |       |   |   |   |   |   |   |
| Canada                  |       | Productive               |       | 2                                        |       | 2 |   | 0 |   | 0 |   |
|                    |       |                     |       |                                     |       |   |   |   |   |   |   |
| 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 114 MMcf per day in the first nine months of 2005.

 

Ourproduction from the Big George coal continues to increase and was 140 MMcf perday gross at October 31, 2005, or 59 MMcf per day net.  In the Big George coal, as of October 31,2005, we had 909 gross wells dewatering and producing gas, 521 gross wellsdewatering and 802 gross wells drilled and in various stages of completion and hook-up inpreparation for dewatering and production.

 

Drillingin the Powder River Basin is dependent on the receipt of various regulatorypermits, including BLM drilling permits, DEQ water discharge permits, and theWyoming State Engineer’s Office reservoir permits.  Most of our undeveloped prospects from theBig George formation are located in the Powder River drainage area.  Water management techniques utilized by us,and approved by the DEQ on a site-specific basis, have included containment ortreating.  In order to facilitate theprocessing of our water discharge permit applications, on the west side of thebasin, and in advance of the receipt of final requirements of the DEQ, we haveinstalled and are evaluating various types of water treatment facilities totest their effectiveness.  We aretreating the water produced in some areas of the basin and, with the approvalof the DEQ, discharging this water into the Powder River.  We believe many of the future developments inthe Big George coal will likely require water treatment facilities.  These treating operations have added and willadd to the cost of development and operations in these areas.  We continue to evaluate several options forwater treatment and are working with the governmental agencies to identifyeffective and cost efficient methods. Depending upon the type of water treatment system, that proves to be themost effective and cost efficient, we may incur additional costs and/or delaysin production to deploy these facilities in all our operating areas.

 

Our2005 capital budget for the Powder River Basin coal bed project is estimated at$103.0 million for the drilling of 850 gross wells, of which $86.2 million wasspent in the first nine months of 2005. In 2005, in the Big George and related coals, we plan to participate inthe drilling of 730 gross wells, or 365 net wells, and in the Wyodak and relatedcoals, we plan to participate in an additional 120 gross wells, or 60 netwells.  Together with our co-developer,we have received the drilling and water discharge permits required for theremainder of our drilling program for 2005. Further, we and our co-developer have received federal drilling permitsand water discharge permits for approximately one-half of our expected 2006drilling program.  There is, however, noassurance as to the future timing of the receipt of drilling and waterdischarge permits, any changes in regulations governing drilling and waterdischarge, restrictions placed on water discharge and/or quality by Wyoming orother states, the success of our drilling program, or the dewatering time asour development progresses into the western and northern parts of the Powder RiverBasin.

 

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

 

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National EnvironmentalPolicy Act, or NEPA. ThisOrder was subsequently appealed.  Asthese cases proceed, the BLM, in the event of any adverse rulings, maybe required to perform further environmental analysis and, in addition, couldbe ordered to cease issuing drilling permits until it has completed suchfurther analysis.   Consequently, ourability to receive permits and develop our leases may be delayed or restrictedby the outcome of these cases.

 

Acomplaint was filed on January 31, 2005 in the U.S. District Court of Wyomingagainst the BLM and the Department of Interior. The complaint alleges that the BLM violated NEPA “as described in *Pennaco Energy, Inc. v. United States Departmentof the Interior*” because the BLM did not consider the effects ofCBM development prior to issuing five leases, including one issued to us.  On July 12, 2005, the plaintiffs amendedtheir complaint by deleting four of the five leases included in their January 31,2005 complaint, including the lease in which we hold an interest.  Additionally, the plaintiffs added 45 otherleases to their Amended Complaint, including nine leases in which we hold aninterest.  These nine leases coverapproximately 5,300 gross and 2,650 net acres. The plaintiffs asked the court for a “review of the issuance” of these leases.  In September 2005, the plaintiffs fileda Notice of Dismissal of this complaint.

 

***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 85 to 90 gross wells, or approximatelyten net wells, on the Pinedale Anticline. Our capital budget for 2005 in the Pinedale Anticline area provides forexpenditures of approximately $52.3 million for drilling costs and productionequipment, of which $38.6 million was spent in the first nine months of2005.  Due to drilling and regulatoryuncertainties, which are beyond our control, including changes to existing airquality, water quality, and/or surface use regulations, there can be noassurance that we will incur this level 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 ofgathering or processing systems in those basins in which we currently operateor in new basins.  We also seek toincrease the efficiency of our operations by modernization of equipment and theconsolidation of existing facilities.

 

*Gas Gathering, Processing andTreating**.*** 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.   Inaddition to our integrated upstream and midstream operations in the PowderRiver and Green River Basins in Wyoming, and in the San Juan Basin in NewMexico, ourcore assets include our plant operations located in west Texas andOklahoma.  We believe that our coreassets have stable production rates, significant proven reserves connected toour systems, provide a significant operating cash flow and continue to provideus with strategic growth opportunities.

 

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.  Inthe third quarter of 2005, we connected the Wamsutter and Red Desert systems intothe acquired assets.

 

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 in Oklahoma.  We currently expect that this facility willbe operational in the second quarter of 2006.

 

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

 
| ** **                    | ** ** | **Year**                | ** ** | **Gas**                      | ** ** | **Gas**                               | ** ** | **Average for the Nine Months  Ended  September 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                                                              |       | 78 |   | — |   |
| Midkiff/Benedum               |       | 1949                    |       | 2,354                        |       | 165                                   |       | 143                                                             |       | 91 |   | 861 |   |
| Mitchell Puckett Treating (5) |       | 1972                    |       | 126                          |       | 120                                   |       | 34                                                              |       | 22 |   | 1 |   |
| Wyoming                       |       |                    |       |                         |       |                                  |       |                                                            |       |   |   |   |   |
| Coal Bed Methane Gathering    |       | 1990                    |       | 1,398                        |       | 548                                   |       | 395                                                             |       | 360 |   | — |   |
| Desert Springs Gathering      |       | 1979                    |       | 65                           |       | 10                                    |       | 6                                                               |       | 5 |   | 22 |   |
| Fort Union Gas Gathering(11)  |       | 1999                    |       | 167                          |       | 635                                   |       | 421                                                             |       | 421 |   | — |   |
| Granger Complex (6)           |       | 1987                    |       | 732                          |       | 332                                   |       | 313                                                             |       | 261 |   | 383 |   |
| Granger Straddle Plant        |       | 2004                    |       | —                       |       | 200                                   |       | 125                                                             |       | — |   | 9 |   |
| Hilight Complex (6)           |       | 1969                    |       | 658                          |       | 124                                   |       | 18                                                              |       | 13 |   | 66 |   |
| Kitty/Amos Draw (6)           |       | 1969                    |       | 321                          |       | 17                                    |       | 5                                                               |       | 3 |   | 24 |   |
| Newcastle (6)                 |       | 1981                    |       | 146                          |       | 5                                     |       | 3                                                               |       | 2 |   | 22 |   |
| Patrick Draw(6) (8)      |       | 1997                    |       | 284                          |       | 150                                   |       | 35                                                              |       | 38 |   | 116 |   |
| Red Desert (6) (13)      |       | 1979                    |       | 137                          |       | 42                                    |       | 23                                                              |       | 34 |   | 80 |   |
| Rendezvous (9)                |       | 2001                    |       | 238                          |       | 325                                   |       | 349                                                             |       | 349 |   | — |   |
| Reno Junction (7)             |       | 1991                    |       | —                       |       | —                                |       | —                                                          |       | — |   | 114 |   |
| Table Rock Gathering          |       | 1979                    |       | 100                          |       | 20                                    |       | 12                                                              |       | 12 |   | — |   |
| Wamsutter Gathering (10)      |       | 1979                    |       | 279                          |       | 50                                    |       | 50                                                              |       | 45 |   | 40 |   |
| Wind River Gathering          |       | 1979                    |       | 137                          |       | 80                                    |       | 48                                                              |       | 48 |   | — |   |
| Oklahoma                      |       |                    |       |                         |       |                                  |       |                                                            |       |   |   |   |   |
| Chaney Dell/Westana           |       | 1966                    |       | 3,382                        |       | 187                                   |       | 201                                                             |       | 177 |   | 313 |   |
| New Mexico                    |       |                    |       |                         |       |                                  |       |                                                            |       |   |   |   |   |
| San Juan River (5)            |       | 1955                    |       | 277                          |       | 60                                    |       | 26                                                              |       | 22 |   | 40 |   |
| Utah                          |       |                    |       |                         |       |                                  |       |                                                            |       |   |   |   |   |
| Four Corners Gathering        |       | 1988                    |       | 104                          |       | 15                                    |       | 3                                                               |       | 2 |   | 18 |   |
| Yellow Creek (8) (12)    |       | 1985                    |       | —                       |       | —                                |       | —                                                          |       | — |   | 74 |   |
| Total                         |       |                    |       | 11,294                       |       | 3,365                                 |       | 2,297                                                           |       | 1,983 |   | 2,183 |   |

 

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| (1)  |   | Our interest in  all facilities is 100% except for Midkiff/Benedum (73%); Newcastle (50%);  Fort Union (14%) 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 September 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, unless otherwise  indicated.                                                                                                                                                                                                                                            |
| (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)  |   | This facility  was acquired in a transaction which was completed on February 1, 2005.                                                                                                                                                                                                                                                                                                                                    |
| (9)  |   | 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.                                                                                                                                                                                                                                             |
| (10) |   | A portion of the  gas gathered by the Wamsutter gas gathering system is delivered to our  Patrick Draw facility and is included with the volume information reported  for Patrick Draw.                                                                                                                                                                                                                                       |
| (11) |   | A portion of the  gas gathered by Fort Union is also reported under Coal Bed Methane Gathering.                                                                                                                                                                                                                                                                                                                               |
| (12) |   | NGL  fractionation facility that receives product from third-parties via liquids  pipeline and truck.                                                                                                                                                                                                                                                                                                                         |
| (13) |   | A portion of  this facility was taken out of operation in the third quarter of 2005. The  gas gathered through this facility is now delivered to the Patrick Draw  facility for processing.                                                                                                                                                                                                                                   |

 

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

##### *** ***

##### *** ***We own and operate MIGC, Inc., an interstatepipeline located in the Powder River Basin, and MGTC, Inc., an intrastatepipeline located in northeast Wyoming. MIGC charges a Federal Energy Regulatory Commission, or FERC, approvedtariff and is connected to pipelines owned by Colorado Interstate Gas Company,Williston Basin Interstate Pipeline Company, Kinder Morgan Interstate PipelineCo., Wyoming Interstate Company, Ltd. and MGTC. MIGC earns fees on a monthly basis from firm capacity contracts underwhich the shipper pays for transport capacity whether or not the capacity isused and from interruptible contracts where a fee is charged based upon volumesreceived into the pipeline.  Contractswith third parties for capacity on MIGC range in duration from one month toapproximately five years, and the fees charged averaged $0.35 per Mcf in thefirst nine months of 2005.  MGTC, apublic utility, provides transportation and gas sales to various cities in Wyomingat rates that are subject to the approval of the Wyoming Public ServiceCommission.

##### *** ***

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

 
| ** **                        | ** ** | ** **                  | ** ** | ** **                | ** ** | **Average for the Nine Months  Ended  September 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                                                             |       | 135 |   |
| MGTC                              |       | 1963                        |       | 251                       |       | 18                                                              |       | 9 |   |
| Total                             |       |                        |       | 514                       |       | 148                                                             |       | 144 |   |

 

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

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

(3)       Aggregatevolumes transported by a pipeline.

 

***Marketing***

 

***Gas*.*   ***We market 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.

 

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**ITEM 3.****          QUANTITATIVEAND QUALITATIVE 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 requirements forour NYMEX transactions.  As a result ofthe recent hurricane damage, the resultant curtailment of oil and gasproduction from the Gulf of Mexico, and impact to the operations of majorrefineries and gas processing facilities in Texas, Louisiana and Mississippi,oil and gas prices have increased substantially.  These increases have resulted in additionalrequired postings of margin deposits totaling $110.7 million at September 30,2005, which has subsequently decreased to $53.8 million on November 7,2005.

 

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.   Additionally,as a result of the damage in the Gulf States caused by hurricanes Katrina andRita, prices increased even more dramatically, and several of ourcounterparties experienced a significant amount of damage to their operatingassets.  In September 2005, one ofour customers, a utility serving the New Orleans area, filed for bankruptcyprotection under Chapter 11 of the Bankruptcy Code.  At the time of the bankruptcy filing, we hadan outstanding account receivable from this utility of $4.1 million.  In the third quarter of 2005, we reserved$800,000 against this amount, which represents our best estimate of the currentmarket value of this receivable.

 

Inorder to minimize our credit exposures, we have utilized existing nettingagreements to reduce our net credit exposure, established new nettingagreements with additional customers, negotiated accelerated payment terms withseveral customers, curtailed sales to certain counterparties, and increased theamount of credit which we make available to substantial companies which meetour credit requirements.  Althoughnetting agreements similar to those that we utilize have been upheld bybankruptcy courts in the past, if any of the customers with whom we havenetting agreements were to file for bankruptcy, we can provide no assurancethat our agreements will not be challenged or as to the outcome of anychallenge.

 

Theuse of financial instruments may expose us to the risk of financial loss insome circumstances, including instances when (i) our equity volumes areless than expected, (ii) our customers fail to purchase or deliver the contractedquantities of natural gas or NGLs, or (iii) our OTC counterparties fail toperform.  To the extent that we engage inhedging activities, we may be prevented from realizing the benefits offavorable price changes in the physical market. However, we are similarly insulated against decreases in these prices.

 

***Risk Policy and Control.**** *Wecontrol the extent of risk management and marketing activities through policiesand procedures that involve the senior level of management.  On a daily basis, our marketing activitiesare audited and monitored by our independent risk oversight department, orIRO.  This department reports to theChief Financial Officer, thereby providing a separation of duties from themarketing department.  Additionally, theIRO reports monthly to the Risk Management Committee, or RMC.  This committee is comprised of corporatemanagers and officers and is responsible for

 

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developing the policiesand guidelines that control the management and measurement of risk, subject tothe approval of the board of directors. The RMC is also responsible for settingrisk limits including value-at-risk and dollar stop loss limits, subject to theapproval of our board of directors.

 

***Hedge Positions.* ** Thehedge contracts are designated and accounted for as cash flow hedges.  As such, gains and losses related to theeffective portions of the changes in the fair value of the derivatives arerecorded in Accumulated other comprehensive income, a component of Stockholders’equity.  Realized gains or losses onthese cash flow hedges are recognized in the Consolidated Statement ofOperations through Sale of gas or Sale of natural gas liquids when the hedgedtransactions occur.

 

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 nine months of 2005, werecognized a loss of $208,000 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 through earningswith changes in market prices and will not be offset by a corresponding mark tomarket on the gas storage and transportation contracts.  For example, at September 30, 2005, we heldgas in our contracted storage facilities and in imbalances of approximately19.5 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 $19.5 million and a $1.00 decreasein the forward price of gas in the anticipated month of withdrawal willincrease pre-tax earnings by $19.5 million. As the stored or transportednatural gas is sold and the future sale derivatives are settled, we willrealize the benefit of the storage and transportation transactions throughearnings.

 

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***Outstanding Equity Hedge Positions and theAssociated Basis for 2005 and 2006.***  The following table details our hedgepositions as of October 31, 2005. In order to determine the hedged price to the particular operatingregion, deduct the basis differential from the settle price.  The prices for NGLs do not include the costof the hedges of approximately $104,000 as of October 31, 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. 

 

45,000 MMBtu per day  with an average minimum price of $9.00 per MMBtu and an average maximum price  of $17.25 per MMBtu. |       | Mid-Continent – 40,000  MMBtu per day with an average basis price of $0.55 per MMBtu. 

 

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

 

San Juan – 7,500 MMBtu  per day with an average basis price of $1.38 per MMBtu. 

 

Rocky Mountain – 20,000  MMBtu per day with an average basis price of $1.44 per MMBtu. 

 

NGPL Texas Oklahoma –  10,000 MMBtu per day with an average basis price of $0.45 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                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |

 

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Accountbalances related to hedging transactions (designated as cash flow hedges underSFAS 133) at September 30, 2005 were $20.4 million in Current assets fromprice risk management activities, $1.3 million in Assets from price riskmanagement activities, $71.6 million in Current liabilities from price riskmanagement activities, $7.2 million in Liabilities from price risk managementactivities, ($20.8) million in Deferred income taxes payable, net, and a $36.2million after-tax unrealized loss in Accumulated other comprehensive income, acomponent of Stockholders’ equity. Approximately $17.9 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 net change in our derivativeposition from December 31, 2004 to September 30, 2005 is as follows(dollars in thousands):

 
| Fair value of contracts outstanding at December 31,  2004         |   | $        | 15,640   |   |
|------------------------------------------------------------------------|--------|----------|----------|--------|
| Decrease in  value due to change in price                              |   | (39,665  | )        |
| Decrease in  value due to new contracts entered into during the period |   | (121,720 | )        |
| (Gains) realized  during the period from existing and new contracts    |   | 6,800    |     |
| Changes in fair value  attributable to changes in valuation techniques |   | —   |     |
| Fair value of  contracts outstanding at September 30, 2005        |   | $        | (138,945 | )      |

 

Asummary of our net outstanding derivative positions at September 30, 2005is as follows (dollars in thousands):

 
| ** **                        | ** ** | **Fair Value of Contracts at September 30,  2005** | ** ** |
|-----------------------------------|------------|---------------------------------------------------------|------------|
| **Source of Fair Value**          | ** ** | **Total  Fair Value**                                   | ** ** | **Maturing  In 2005** | ** ** | **Maturing In  2006-2007** | ** ** | **Maturing In  2008-2009** | ** ** | **Maturing  Thereafter** | ** ** |
| Exchange  published prices        |       | $                                                       | (75,654    | ) | $ | (40,282 | ) | $ | (35,372 | ) | — |   | — |   |
| Other actively quoted  prices (1) |       | 9,912                                                   |       | 8,507 |   | 1,371 |   | $ | 34 |   | — |   |
| Other valuation  methods (2)      |       | (73,203                                                 | )          | (40,908 | ) | (32,744 | ) | 449 |   | — |   |
| Total fair value                  |       | $                                                       | (138,945   | ) | $ | (72,683 | ) | $ | (66,745 | ) | $ | 483 |   | — |   |

 

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

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

 

***Foreign Currency DerivativeMarket Risk***. As a normal part of our business, we enter into physical gastransactions which are payable in Canadian dollars.  We enter into forward purchases and sales ofCanadian dollars from time to time to fix the cost of our future Canadiandollar denominated natural gas purchase, sale, storage, and transportationobligations.  This is done to protectmarketing margins from adverse changes in the United States and Canadian dollarexchange rate between the time the commitment for the payment obligation ismade and the actual payment date of such obligation.  As of September 30, 2005, we had soldforward contracts for  $53.1 million inCanadian dollars in exchange for $45.0 million in United States dollars, andthe fair market value of these contracts was a loss of  $1.1 million in United States dollars.

 

**ITEM 4.****          CONTROLSAND PROCEDURES**

 

***Disclosure Controls and Procedures.***

 

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 September 30, 2005.Notwithstanding this material weakness, the Company’s management believes thatthe consolidated financial condition, results of operations and cash flows arefairly presented in this Form 10-Q.

 

***Remediation Efforts toAddress 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 OverFinancial Reporting.***

 

There were nomaterial changes to internal controls over financial reporting during the firstquarter ended September 30, 2005, that have materially affected, or arereasonably likely 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.

 

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**PART II - OTHER INFORMATION**

 

**ITEM1.    LEGAL PROCEEDINGS**

 

Reference is made to “Notes to Consolidated FinancialStatements (Unaudited)  – LegalProceedings,” in Item 1 of this Form 10-Q and incorporated by reference inthis Item 1.

 

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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        |       | Remuneration  of Directors (previously filed as Exhibit 10.1 to our Current Report on Form 8-K  filed on July 21, 2005 and incorporated herein by reference).*                                                                                             |
|        |       |                                                                                                                                                                                                                                                                      |
| 10.2        |       | Employment  Agreement, dated August 1, 2005, by and between Western Gas Resources, Inc.  and Peter A. Dea (previously filed as Exhibit 10.1 to our Current Report  on Form 8-K filed on August 2, 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)       |
|                               |                              |                                                     |  |  |

 

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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        |       | Remuneration of  Directors (previously filed as Exhibit 10.1 to our Current Report on Form 8-K  filed on July 21, 2005 and incorporated herein by reference).*                                                                                             |
|        |       |                                                                                                                                                                                                                                                                      |
| 10.2        |       | Employment  Agreement, dated August 1, 2005, by and between Western Gas Resources, Inc.  and Peter A. Dea (previously filed as Exhibit 10.1 to our Current Report  on Form 8-K filed on August 2, 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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