**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

**FORM 10-Q**

**(Mark One)**

 

| **ý**                                                                                                                                                                                                                                                                    |   | **QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE  SECURITIES EXCHANGE ACT OF 1934**  |
|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|-----------------------------------------------------------------------------------------------|
|                                                                                                                                                                                                                                                                          |   |                                                                                          |
| **FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2003 OR**                                                                                                                                                                                                                          |
|                                                                                                                                                                                                                                                                          |   |                                                                                          |
| **o**                                                                                                                                                                                                                                                                         |   | **TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE  SECURITIES EXCHANGE ACT OF 1934** |
|                                                                                                                                                                                                                                                                          |   |                                                                                          |   |   |
| **FOR  THE TRANSITION PERIOD FROM                       TO                   ** |

 

**Commissionfile number 1-10389**

 

**WESTERN GAS RESOURCES, INC.**

(Exact name of registrantas specified in its charter)

 

| **Delaware**                                                                         |   | **84-1127613**                        |
|--------------------------------------------------------------------------------------|--------|---------------------------------------|
| (State or other  jurisdiction of  incorporation or organization)                     |   | (I.R.S. Employer  Identification No.) |
|                                                                                 |   |                                  |
| **1099  18th Street, Suite 1200, Denver, Colorado**                                  |   | **80202**                             |
| (Address of  principal executive offices)                                            |   | (Zip Code)                            |
|                                                                                 |   |                                  |
| **(303)  452-5603**                                                                  |
| Registrant’s  telephone number, including area code                             |
|                                                                                 |   |                                  |
|                                                                                 |   |                                  |
| (Former name,  former address and former fiscal year, if changed since last report). |

 

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

 

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

 

On May 1, 2003, there were 33,162,506 shares of the registrant’s CommonStock outstanding.

 

 

----

 

**Western Gas Resources, Inc.**

**Form 10-Q**

**Table of Contents**

 
| PART I  - Financial Information |    |
|---------------------------------|---------|
|                            |    |   |
|                            | Item 1. | Financial Statements |
|                            |    |   |
|                            |    | Consolidated Balance Sheet - March 31,  2003 and December 31, 2002 |
|                            |    |   |
|                            |    | Consolidated Statement of Cash Flows - Three  Months Ended March 31, 2003 and 2002 |
|                            |    |   |
|                            |    | Consolidated Statement of Operations - Three  Months Ended March 31, 2003 and 2002 |
|                            |    |   |
|                            |    | Consolidated Statement of Changes in  Stockholders’ Equity - Three Months Ended March 31, 2003 |
|                            |    |   |
|                            |    | 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 and Reports on Form 8-K |
|                            |    |   |
| Signatures                      |
|                                 |         |  |  |  |

 

2

----

 

**PART I****- FINANCIAL INFORMATION**

 

**ITEM 1**.          FINANCIAL STATEMENTS

 

WESTERNGAS RESOURCES, INC.

CONSOLIDATED BALANCE SHEET

(Dollars inthousands, except share data)

 
|                                                                                                                               |   | **March 31,2003** |      | **December  31,2002** |    |
|------------------------------------------------------------------------------------------------------------------------------------|--------|-------------------|-----------|-----------------------|---------|
|                                                                                                                               |   | **(unaudited)**   |      |                  |    |
| ASSETS                                                                                                                             |   |              |      |                  |    |
|                                                                                                                               |   |              |      |                  |    |
| Current  assets:                                                                                                                   |   |              |      |                  |    |
| Cash  and cash equivalents                                                                                                         |   | $                 | 13,188    |                  | $       | 7,312 |   |
| Trade  accounts receivable, net                                                                                                    |   | 426,880           |      | 253,587               |    |
| Inventory                                                                                                                          |   | 23,217            |      | 43,482                |    |
| Assets  held for sale                                                                                                              |   | 4,369             |      | 3,250                 |    |
| Assets  from price risk management activities                                                                                      |   | 26,244            |      | 34,873                |    |
| Other                                                                                                                              |   | 3,250             |      | 27,744                |    |
| Total  current assets                                                                                                              |   | 497,148           |      | 370,248               |    |
| Property  and equipment:                                                                                                           |   |              |      |                  |    |
| Gas  gathering, processing, storage and transportation                                                                             |   | 995,946           |      | 942,147               |    |
| Oil  and gas properties and equipment (successful efforts method)                                                                  |   | 270,831           |      | 252,747               |    |
| Construction  in progress                                                                                                          |   | 98,424            |      | 104,033               |    |
|                                                                                                                               |   | 1,365,201         |      | 1,298,927             |    |
| Less:  Accumulated depreciation, depletion and  amortization                                                                  |   | (453,629          | )         | (432,281              | )  |
| Total property  and equipment, net                                                                                                 |   | 911,572           |      | 866,646               |    |
|                                                                                                                               |   |              |      |                  |    |
| Other  assets:                                                                                                                     |   |              |      |                  |    |
| Gas  purchase contracts (net of accumulated amortization of $37,572 and $37,232,  respectively)                                    |   | 30,583            |      | 30,924                |    |
| Assets  from price risk management activities                                                                                      |   | 939               |      | 406                   |    |
| Other                                                                                                                              |   | 32,348            |      | 33,920                |    |
| Total other  assets                                                                                                                |   | 63,870            |      | 65,250                |    |
| TOTAL ASSETS                                                                                                                       |   | $                 | 1,472,590 |                  | $       | 1,302,144 |   |
|                                                                                                                               |   |              |      |                  |    |
| LIABILITIES AND  STOCKHOLDERS’ EQUITY                                                                                         |   |              |      |                  |    |
| Current  liabilities:                                                                                                              |   |              |      |                  |    |
| Accounts  payable                                                                                                                  |   | $                 | 421,515   |                  | $       | 242,987 |   |
| Accrued  expenses                                                                                                                  |   | 42,539            |      | 51,509                |    |
| Liabilities  from price risk management activities                                                                                 |   | 39,552            |      | 34,811                |    |
| Dividends  payable                                                                                                                 |   | 3,469             |      | 3,464                 |    |
| Total  current liabilities                                                                                                         |   | 507,075           |      | 332,771               |    |
|                                                                                                                               |   |              |      |                  |    |
| Long-term  debt                                                                                                                    |   | 309,833           |      | 359,933               |    |
| Liabilities  from price risk management activities                                                                                 |   | 914               |      | 406                   |    |
| Other  long-term liabilities                                                                                                       |   | 20,583            |      | 1,713                 |    |
| Deferred  income taxes payable, net                                                                                                |   | 134,127           |      | 124,253               |    |
|                                                                                                                               |   |              |      |                  |    |
| Total  liabilities                                                                                                                 |   | 972,532           |      | 819,076               |    |
|                                                                                                                               |   |              |      |                  |    |
| Stockholders’  equity:                                                                                                        |   |              |      |                  |    |
| Preferred  Stock; 10,000,000 shares authorized:                                                                                    |   |              |      |                  |    |
| $ 2.625  cumulative convertible preferred stock, par value $.10; 2,760,000 issued  ($138,000,000 aggregate liquidation preference) |   | 276               |      | 276                   |    |
| Common  stock, par value $.10; 100,000,000 shares authorized; 33,153,541 and  33,077,611 shares issued, respectively               |   | 3,336             |      | 3,329                 |    |
| Treasury  stock, at cost; 25,016 common shares in treasury                                                                         |   | (788              | )         | (788                  | )  |
| Additional  paid-in capital                                                                                                        |   | 382,474           |      | 381,066               |    |
| Retained  earnings                                                                                                                 |   | 122,198           |      | 102,292               |    |
| Accumulated  other comprehensive income                                                                                            |   | (7,143            | )         | (2,812                | )  |
| Notes  receivable from key employees secured by common stock                                                                       |   | (295              | )         | (295                  | )  |
|                                                                                                                               |   |              |      |                  |    |
| Total  stockholders’ equity                                                                                                   |   | 500,058           |      | 483,068               |    |
| TOTAL  LIABILITIES AND STOCKHOLDERS’ EQUITY                                                                                   |   | $                 | 1,472,590 |                  | $       | 1,302,144 |   |

 

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

 

3

----

 

WESTERN GAS RESOURCES,INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

(Dollars inthousands)
|                                                                                    |   | **Three  Months Ended  March 31,** |   |
|-----------------------------------------------------------------------------------------|--------|------------------------------------|--------|
|                                                                                    |   | **2003**                           |   | **2002** |   |
| Reconciliation  of net income to net cash provided by operating activities:             |   |                               |   |   |   |
| Net  income                                                                             |   | $                                  | 23,375 |   | $ | 8,000 |   |
| Add  income items that do not affect cash:                                              |   |                               |   |   |   |
| Depreciation,  depletion and amortization                                               |   | 18,143                             |   | 17,946 |   |
| Gain  on the sale of property and equipment                                             |   | 281                                |   | 9 |   |
| Deferred income taxes                                                                   |   | 17,183                             |   | 3,836 |   |
| Non-cash change in fair value of derivatives                                            |   | 4,163                              |   | 10,995 |   |
| Cumulative effect of change in accounting principle                                     |   | 6,724                              |   | — |   |
| Other  non-cash items, net                                                              |   | 2,208                              |   | (27 | ) |
|                                                                                    |   |                               |   |   |   |
| Adjustments  to working capital to arrive at net cash provided by operating activities: |   |                               |   |   |   |
| Increase  in trade accounts receivable                                                  |   | (173,095                           | )      | (15,476 | ) |
| Decrease  in product inventory                                                          |   | 20,308                             |   | 25,851 |   |
| Decrease  in other current assets                                                       |   | 26,797                             |   | 651 |   |
| Increase  in other assets and liabilities, net                                          |   | (343                               | )      | (71 | ) |
| Increase  (decrease) in accounts payable                                                |   | 178,528                            |   | (36,009 | ) |
| Increase  (decrease) in accrued expenses                                                |   | (9,117                             | )      | 6,820 |   |
|                                                                                    |   |                               |   |   |   |
| Net  cash provided by operating activities                                              |   | 115,155                            |   | 22,525 |   |
|                                                                                    |   |                               |   |   |   |
| Cash  flows from investing activities:                                                  |   |                               |   |   |   |
|                                                                                    |   |                               |   |   |   |
| Purchases of  property and equipment                                                    |   | (57,076                            | )      | (26,896 | ) |
| Proceeds  from the dispositions of property and equipment                               |   | 41                                 |   | 32 |   |
| Contributions  to equity investees                                                      |   | —                             |   | (4,702 | ) |
|                                                                                    |   |                               |   |   |   |
| Net  cash used in investing activities                                                  |   | (57,035                            | )      | (31,566 | ) |
|                                                                                    |   |                               |   |   |   |
| Cash  flows from financing activities:                                                  |   |                               |   |   |   |
|                                                                                    |   |                               |   |   |   |
| Proceeds from  exercise of common stock options                                         |   | 1,268                              |   | 5,477 |   |
| Payments  on revolving credit facility                                                  |   | (391,800                           | )      | (279,400 | ) |
| Borrowings  on long-term debt                                                           |   | 25,000                             |   | — |   |
| Borrowings  under revolving credit facility                                             |   | 316,700                            |   | 282,600 |   |
| Debt  issue costs                                                                       |   | (95                                | )      | — |   |
| Effect  of re-priced options                                                            |   | 147                                |   | 343 |   |
| Dividends  paid                                                                         |   | (3,464                             | )      | (3,767 | ) |
|                                                                                    |   |                               |   |   |   |
| Net  cash provided by (used in) financing activities                                    |   | (52,244                            | )      | 5,253 |   |
|                                                                                    |   |                               |   |   |   |
| Net  increase (decrease) in cash and cash equivalents                                   |   | 5,876                              |   | (3,788 | ) |
|                                                                                    |   |                               |   |   |   |
| Cash  and cash equivalents at beginning of period                                       |   | 7,312                              |   | 10,032 |   |
|                                                                                    |   |                               |   |   |   |
| Cash  and cash equivalents at end of period                                             |   | $                                  | 13,188 |   | $ | 6,244 |   |

 

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

4

----

 

WESTERN GASRESOURCES, INC.

CONSOLIDATED STATEMENT OF OPERATIONS

(Unaudited)

(Dollars inthousands, except share and per share amounts)

 
|                                                                                                |   | **Three  Months Ended  March 31,** |    |
|-----------------------------------------------------------------------------------------------------|--------|------------------------------------|---------|
|                                                                                                |   | **2003**                           |    | **2002** |   |
| Revenues:                                                                                           |   |                               |    |   |   |
| Sale  of gas                                                                                        |   | $                                  | 779,739 |   | $ | 545,589 |   |
| Sale  of natural gas liquids                                                                        |   | 92,049                             |    | 64,807 |   |
| Gathering,  processing and transportation revenue                                                   |   | 19,777                             |    | 15,431 |   |
| Non-cash  change in fair value of derivatives                                                       |   | (4,163                             | )       | (10,995 | ) |
| Other                                                                                               |   | 704                                |    | 1,083 |   |
|                                                                                                |   |                               |    |   |   |
| Total  revenues                                                                                     |   | 888,106                            |    | 615,915 |   |
|                                                                                                |   |                               |    |   |   |
| Costs  and expenses:                                                                                |   |                               |    |   |   |
| Product  purchases                                                                                  |   | 771,602                            |    | 544,606 |   |
| Plant  and transportation operating expense                                                         |   | 21,922                             |    | 18,871 |   |
| Oil  and gas exploration and production expense                                                     |   | 12,511                             |    | 7,389 |   |
| Depreciation,  depletion and amortization                                                           |   | 18,143                             |    | 17,946 |   |
| (Gain)  loss on sale of assets                                                                      |   | 281                                |    | 9 |   |
| Selling  and administrative expense                                                                 |   | 10,592                             |    | 8,691 |   |
| Earnings  from equity investments                                                                   |   | (1,562                             | )       | (851 | ) |
| Interest  expense                                                                                   |   | 6,814                              |    | 6,660 |   |
|                                                                                                |   |                               |    |   |   |
| Total  costs and expenses                                                                           |   | 840,303                            |    | 603,321 |   |
|                                                                                                |   |                               |    |   |   |
| Income  before taxes                                                                                |   | 47,803                             |    | 12,594 |   |
|                                                                                                |   |                               |    |   |   |
| Provision  for income taxes:                                                                        |   |                               |    |   |   |
| Current                                                                                             |   | 521                                |    | 758 |   |
| Deferred                                                                                            |   | 17,183                             |    | 3,836 |   |
| Total provision for income taxes                                                                    |   | 17,704                             |    | 4,594 |   |
|                                                                                                |   |                               |    |   |   |
| Income  before Cumulative effect of change in accounting principle                                  |   | 30,099                             |    | 8,000 |   |
|                                                                                                |   |                               |    |   |   |
| Cumulative  effect of change in accounting principle, net of tax benefit of $3,967                  |   | (6,724                             | )       | — |   |
|                                                                                                |   |                               |    |   |   |
| Net  income                                                                                         |   | 23,375                             |    | 8,000 |   |
|                                                                                                |   |                               |    |   |   |
| Preferred  stock requirements                                                                       |   | (1,811                             | )       | (2,130 | ) |
|                                                                                                |   |                               |    |   |   |
| Income  attributable to common stock                                                                |   | $                                  | 21,564  |   | $ | 5,870 |   |
|                                                                                                |   |                               |    |   |   |
| Net  income per share of common stock before cumulative effect of a change in  accounting principle |   |                               |    |   |   |
|                                                                                                | $      | .85                                |    | $ | .18 |   |
|                                                                                                |   |                               |    |   |   |
| Cumulative effect of a change in accounting  principle                                              |   | $                                  | .20     |   | $ | — |   |
|                                                                                                |   |                               |    |   |   |
| Earnings per share of common stock                                                                  |   | $                                  | .65     |   | $ | .18 |   |
|                                                                                                |   |                               |    |   |   |
| Weighted  average shares of common stock outstanding                                                |   | 33,087,680                         |    | 32,760,081 |   |
|                                                                                                |   |                               |    |   |   |
| Income  attributable to common stock - assuming dilution                                            |   | $                                  | 23,375  |   | $ | 5,870 |   |
|                                                                                                |   |                               |    |   |   |
| Earnings per share of common stock - assuming  dilution                                             |   | $                                  | .63     |   | $ | 18 |   |
|                                                                                                |   |                               |    |   |   |
| Weighted  average shares of common stock outstanding - assuming dilution                            |   | 37,163,098                         |    | 33,457,239 |   |

 

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

 

5

----

 

WESTERN GASRESOURCES, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

(Dollars inthousands, except share amounts)

 
|                                                                 |   | **$ 2.625  Cumulative  Convertible  Preferred  Stock** |   | **Shares  of Common  Stock** |   | **Shares  of Common  Stock  in Treasury** |   | **$ 2.625  Cumulative  Convertible  Preferred  Stock** |   | **Common  Stock** |   | **Treasury  Stock** |   | **Additional  Paid-In  Capital** |   | **Retained  Earnings** |   | **Accumulated  Other  Comprehensive  Income  Net of Tax** |   | **Notes  Receivable  from Key  Employees** |    | **Total  Stock-  holders'  Equity** |   |
|----------------------------------------------------------------------|--------|--------------------------------------------------------|--------|------------------------------|--------|-------------------------------------------|--------|--------------------------------------------------------|--------|-------------------|--------|---------------------|--------|----------------------------------|--------|------------------------|--------|-----------------------------------------------------------|--------|--------------------------------------------|---------|-------------------------------------|--------|
|                                                                 |   |                                                   |   |                         |   |                                      |   |                                                   |   |              |   |                |   |                             |   |                   |   |                                                      |   |                                       |    |                                |   |
| Balance at December 31, 2002                                         |   | 2,760,000                                              |   | 33,077,611                   |   | 25,016                                    |   | $                                                      | 276    |              | $      | 3,329               |   | $                                | (788   | )                      | $      | 381,066                                                   |   | $                                          | 102,292 |                                | $      | (2,812 | ) | $ | (295 | ) | $ | 483,068 |   |
| Comprehensive income:                                                |   |                                                   |   |                         |   |                                      |   |                                                   |   |              |   |                |   |                             |   |                   |   |                                                      |   |                                       |    |                                |   |
| Net income, three months ended March 31, 2003                        |   | —                                                 |   | —                       |   | —                                    |   | —                                                 |   | —            |   | —              |   | —                           |   | 23,375                 |   | —                                                    |   | —                                     |    | 23,375                              |   |
| Translation adjustments                                              |   | —                                                 |   | —                       |   | —                                    |   | —                                                 |   | —            |   | —              |   | —                           |   | —                 |   | 582                                                       |   | —                                     |    | 582                                 |   |
| Reclassification adjustment for settled contracts                    |   | —                                                 |   | —                       |   | —                                    |   | —                                                 |   | —            |   | —              |   | —                           |   | —                 |   | 1,669                                                     |   | —                                     |    | 1,669                               |   |
| Changes in fair value of outstanding hedging  positions              |   | —                                                 |   | —                       |   | —                                    |   | —                                                 |   | —            |   | —              |   | —                           |   | —                 |   | (6,548                                                    | )      | —                                     |    | (6,548                              | )      |
| Reduction due to estimated ineffectiveness                           |   | —                                                 |   | —                       |   | —                                    |   | —                                                 |   | —            |   | —              |   | —                           |   | —                 |   | (34                                                       | )      | —                                     |    | (34                                 | )      |
| Change in accumulated derivative comprehensive  income               |   | —                                                 |   | —                       |   | —                                    |   | —                                                 |   | —            |   | —              |   | —                           |   | —                 |   | (4,913                                                    | )      | —                                     |    | (4,913                              | )      |
|                                                                 |   |                                                   |   |                         |   |                                      |   |                                                   |   |              |   |                |   |                             |   |                   |   |                                                      |   |                                       |    |                                |   |
| Total comprehensive income, net of tax                               |   |                                                   |   |                         |   |                                      |   |                                                   |   |              |   |                |   |                             |   |                   |   |                                                      |   |                                       |    | 19,044                              |   |
|                                                                 |   |                                                   |   |                         |   |                                      |   |                                                   |   |              |   |                |   |                             |   |                   |   |                                                      |   |                                       |    |                                |   |
| Stock options exercised                                              |   | —                                                 |   | 75,930                       |   | —                                    |   | —                                                 |   | 7                 |   | —              |   | 1,261                            |   | —                 |   | —                                                    |   | —                                     |    | 1,268                               |   |
|                                                                 |   |                                                   |   |                         |   |                                      |   |                                                   |   |              |   |                |   |                             |   |                   |   |                                                      |   |                                       |    |                                |   |
| Effect of re-priced stock options                                    |   | —                                                 |   | —                       |   | —                                    |   | —                                                 |   | —            |   | —              |   | 147                              |   | —                 |   | —                                                    |   | —                                     |    | 147                                 |   |
| Dividends declared on common stock                                   |   | —                                                 |   | —                       |   | —                                    |   | —                                                 |   | —            |   | —              |   | —                           |   | (1,658                 | )      | —                                                    |   | —                                     |    | (1,658                              | )      |
| Dividends declared on $2.625 cumulative  convertible preferred stock |   | —                                                 |   | —                       |   | —                                    |   | —                                                 |   | —            |   | —              |   | —                           |   | (1,811                 | )      | —                                                    |   | —                                     |    | (1,811                              | )      |
|                                                                 |   |                                                   |   |                         |   |                                      |   |                                                   |   |              |   |                |   |                             |   |                   |   |                                                      |   |                                       |    |                                |   |
| Balance at March 31, 2003                                            |   | 2,760,000                                              |   | 33,153,541                   |   | 25,016                                    |   | $                                                      | 276    |              | $      | 3,336               |   | $                                | (788   | )                      | $      | 382,474                                                   |   | $                                          | 122,198 |                                | $      | (7,143 | ) | $ | (295 | ) | $ | 500,058 |   |

 

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

 

6

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WESTERN GASRESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS

(Unaudited)

** **

***GENERAL***

 

The interim consolidatedfinancial statements presented herein should be read in conjunction with theConsolidated Financial Statements and Notes thereto included in our AnnualReport on Form 10-K for the year ended December 31, 2002.  The interim consolidated financialstatements as of March 31, 2003 and for the three month periods ended March 31,2003 and 2002 included herein are unaudited but reflect, in the opinion of management,all adjustments (which include only normal recurring adjustments) necessary tofairly present the results for such periods. The results of operations for the three months ended March 31, 2003 arenot necessarily indicative of the results of operations expected for the yearended December 31, 2003.

 

Prior period amounts inthe interim consolidated financial statements and notes have been reclassifiedas appropriate to conform to the presentation used in 2003.

 

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

 

Earningsper share of common stock are computed by dividing income attributable tocommon stock by the weighted average shares of common stock outstanding.  In addition, earnings per share of commonstock - assuming dilution is computed by dividing income attributable to commonstock by the weighted average shares of common stock outstanding as adjustedfor potential common shares.  Incomeattributable to common stock is income less preferred stock dividends.  We declared preferred stock dividends of$1.8 million and $2.1 million for the three-month periods ended March 31, 2003and 2002, respectively.  Common stockoptions and our $2.625 Cumulative Convertible Preferred Stock are potentialcommon shares.  Outstanding common stockoptions in both three-month periods and our $2.625 Cumulative ConvertiblePreferred Stock, which is convertible into 3,471,698 shares of common stock, inthe three months ended March 31, 2003, had a dilutive effect on earnings.  This resulted in an increase in the weightedaverage number of shares of common stock outstanding by 4,075,418 and 697,158for the three-month periods ended March 31, 2003 and 2002, respectively.  The numerators and the denominators forthese periods were adjusted to reflect these potential shares and any relatedpreferred dividends in calculating fully diluted earnings per share.

** **

***ACCUMULATED OTHER COMPREHENSIVE INCOME***

** **

Includedin Accumulated other comprehensive income at March 31, 2003 were unrealizedlosses of  $10.3 million from the fairvalue of derivatives designated as cash flow hedges and unrealized gains of$3.2 million of cumulative foreign currency translation adjustments.

** **

Includedin Accumulated other comprehensive income at March 31, 2002 were unrealizedgains of $4.7 million from the fair value of derivatives designated as cashflow hedges and $1.9 million of cumulative foreign currency translationadjustments.

 

***CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTINGPRINCIPLE***

 

InJune 2001, the FASB issued SFAS No. 143 “Accounting for Asset RetirementObligations.”  SFASNo. 143 is effective for fiscal years beginning after June 15, 2002.  SFAS No. 143 establishes accountingstandards for recognition and measurement of a liability for an assetretirement obligation and the associated asset retirement cost.  We adopted SFAS No. 143 on January 1, 2003 andrecorded a $11.5 million increase to Property and Equipment, a $4.4 millionincrease to Accumulated depreciation, depletion and amortization, a$17.8 million increase to Other long-term liabilities and a $6.7 millionnon-cash, after-tax loss from the Cumulativeeffect of a change in accounting principle.

 

The following is a reconciliation of theasset retirement obligation for the three months ended March 31, 2003 (dollarsin thousands):

 

| Asset  retirement obligation as of January 1, 2003 |   | $   | 17,801 |   |
|----------------------------------------------------|--------|-----|--------|--------|
| Liability  accrued upon capital expenditures       |   | 977 |   |
| Liability  settled                                 |   | (42 | )      |
| Accretion  of discount expense                     |   | 277 |   |
| Asset  retirement obligation as of March 31, 2003  |   | $   | 19,013 |   |

 

7

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Exclusive of assets disposed of during 2002, if we hadadopted SFAS No. 143 as of January 1, 2002, we estimate that the assetretirement obligation at that date would have been $15.7 million, based on thesame assumptions used in our calculation of the obligation at January 1, 2003.  The estimated 2002 pro forma effect ofJanuary 1, 2002 adoption of SFAS No. 143 on net income and earnings per share,for annual and interim periods, is not material.

 

##### ***In connection with the adoption of SFAS No. 143, wecompleted a review of our operating assets and reevaluated the operating lifeand salvage values of the associated equipment. ***As a result of this evaluation, weextended the useful life of many of our operating assets and adjusted theestimated salvage value of our operating equipment.  These adjustments resulted in an approximate $2.5 million, or$0.04 per share ofcommon stock - assuming dilution, decrease in depreciation, depletion and amortization in thethree months ended March 31, 2003 from the expense calculated using theprevious useful lives.  The adjustmentsto the salvage value and depreciable lives of our assets are treated as arevision of an estimate and will be accounted for on a prospective basis.

 

***OTHER INFORMATION***

 

***Acquisition of Gathering Systems.***  Effective February 1, 2003, we acquired 18gathering systems in Wyoming, primarily located in the Green River Basin withsmaller operations in the Powder River and Wind River Basins, for a total of$37.1 million.  These assets were acquiredfrom El Paso Field Services, or EPFS, and related entities.  The three largest systems are located in theWamsutter area of the Greater Green River Basin.   Four of these systems are located in the Wind River Basin andprovide us with the opportunity to expand our gathering and processing activitiesinto an area in which we have not previously operated.  Several of the systems located in the PowderRiver Basin do not integrate directly into our existing systems and will likelybe disposed of.  These systems areclassified as Assets held for sale on the Consolidated Balance Sheet at March31, 2003.  During the first quarter of2003, the facilities, which are included in Assets held for sale, generated netafter-tax earnings of approximately $94,000, or $0.00 per share of commonstock.  We believe the results fromthese facilities are immaterial for separate presentation as a discontinuedoperation.

 

***Corporate Offices.***  In August 2002, we entered into a lease witha seven year and nine month term for approximately 85,000 square feet of officespace in Denver, Colorado.  Thecumulative lease payments over the term of this agreement, which began uponoccupancy, will total approximately $10.7 million.  Our corporate offices were relocated to this space in March2003.  At March 31, 2003, the officebuilding we previously occupied was reflected on the Consolidated Balance Sheetas an Asset held for sale.  We completedthe sale of this building in April 2003.

 

**DERIVATIVE INSTRUMENTS AND HEDGINGACTIVITIES**

 

Thenet loss recognized in earnings through Sale of residue gas and Sale of naturalgas liquids during the first three months of 2003 from hedging activities was$12.7 million.  Additionally, werecognized a net of a loss of $53,000 resulting from hedge ineffectiveness dueto the use of crude oil swaps in hedging the variability in the sales price ofnormal butane.  Overall, our hedges areexpected to continue to be “highly effective” under SFAS No. 133 in thefuture.  An additional $2.8 million oflosses were reclassified into earnings as a result of the discontinuance ofcash flow hedges.  These cash flowhedges were discontinued due to the reduction of forecasted production volumes.

 

The gains and losses currently reflected in Accumulated othercomprehensive income will be reclassified to earnings based on the actual salesof the hedged gas or NGLs.  Based onprices as of March 31, 2003, approximately $10.3 million of losses inAccumulated other comprehensive income will be reclassified to earnings in thenext nine months.

 

***SUPPLEMENTARYCASH FLOW INFORMATION***

 

Interest paid was $3.1million and $3.0 million for the three months ended March 31, 2003 and 2002,respectively. A total of $4.9 million waspaid in income taxes in the three months ended March 31, 2003.  No income taxes were paid during the three monthsended March 31, 2002.

 

***STOCK COMPENSATION***

 

Aspermitted under SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFASNo. 123”), we have elected to continue to measure compensation costs forstock-based employee compensation plans as prescribed by Accounting PrinciplesBoard Opinion No. 25, “Accounting for Stock Issued to Employees.”  We have complied with the pro formadisclosure requirements of SFAS No. 123 as required under the pronouncement.  We realize an income tax benefit from theexercise of non-qualified stock options related to the amount by which themarket price at the date of exercise exceeds the option price.  This tax benefit is credited to additionalpaid-in capital.

 

Weare required to record compensation expense (if not previously accrued) equalto the number of unexercised re-priced options multiplied by the amount bywhich our stock price at the end of any quarter exceeds $21.00 per share.  We had re-priced options covering 59,500common shares outstanding at March 31, 2003 and 78,000 common sharesoutstanding at March 31, 2002.  Based onour stock price at March 31, 2003 of $32.55 and our stock price at March 31,2002 of $37.22 per share, compensation expense of $53,000 and $372,000 wasrecorded in the three months ended March 31, 2003 and 2002, respectively.

 

8

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SFASNo. 123 encourages companies to record compensation expense for stock-basedcompensation plans at fair value.  Aspermitted under SFAS No. 123, we have elected to continue to measurecompensation costs for such plans as prescribed by APB No. 25.  SFAS No. 123 requires pro forma disclosuresfor each quarter that a statement of operations is presented.  During the three months ended March 31,2003, there were grants under the 2002 Plan. During the three months ended March 31, 2002, there were no grants underany stock option plan.  The weightedaverage fair value of options granted during the first quarter of 2003 underthe 2002 Plan was $18.28 per option. This value was estimated using the Black-Scholes option-pricing modelwith the following assumptions:

 

| Stock Option Plan               |   | 2002 |   |
|---------------------------------|--------|------|--------|
| Risk-free interest  rate        |   | 3.37 | %      |
| Expected life (in  years)       |   | 5    |   |
| Expected volatility             |   | 55   | %      |
| Expected dividends  (quarterly) |   | $    | 0.05   |   |
|                                 |        |      |        |  |

 

Ifwe had recorded compensation expense for our grants under our stock-basedcompensation plans consistent with the fair value method under SFAS No. 123,our net income, income attributable to common stock, earnings per share ofcommon stock and earnings per share of common stock - assuming dilution wouldapproximate the pro forma amounts below (dollars in thousands, except per shareamounts):

 
|                                                                                                                                           |   | **Three  Months Ended March 31,** |   |
|------------------------------------------------------------------------------------------------------------------------------------------------|--------|-----------------------------------|--------|
|                                                                                                                                           |   | **2003**                          |   | **2003** |   | **2002** |   | **2002** |   |
|                                                                                                                                           |   | **As  Reported**                  |   | **Pro Forma** |   | **As  Reported** |   | **Pro Forma** |   |
| Net income                                                                                                                                     |   | $                                 | 23,375 |   | $ | 22,610 |   | $ | 8,000 |   | $ | 7,400 |   |
| Net  income attributable to common stock                                                                                                       |   | 21,564                            |   | 20,799 |   | 5,870 |   | 5,270 |   |
| Earnings per share of common stock                                                                                                             |   | 0.65                              |   | 0.63 |   | 0.18 |   | 0.16 |   |
| Earnings  per share of common stock  - assuming  dilution                                                                                 |   | 0.63                              |   | 0.61 |   | 0.18 |   | 0.16 |   |
| Stock-based  employee compensation cost, net of related tax effects, included in net  income                                                   |   | $                                 | 92     |   | $ | — |   | $ | 295 |   | $ | — |   |
| Stock-based  employee compensation cost, net of related tax effects, includable in net  income if the fair value based method had been applied |   | $                                 | — |   | $ | 857 |   | $ | — |   | $ | 895 |   |

 

Thefair market value of the options at grant date is amortized over theappropriate vesting period for purposes of calculating compensation expense.

 

***SEGMENTREPORTING***

 

Weoperate in four principal business segments, as follows:  Gas Gathering, Processing and Treating;Exploration and Production; Marketing; and Transportation.  Management separately monitors thesesegments for 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 the 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.  Except for volumes taken inkind by our producers, the Marketing segment sells the residue gas and NGLsextracted at most of our facilities.  Inthis segment, we recognize revenue for our services at the time the service isperformed.

 

Substantially all gasflowing through our gathering, processing and treating facilities is suppliedunder three types of contracts providing for the purchase, treating orprocessing of natural gas for periods ranging from one month to twenty years orin some cases for the life of the oil and gas lease.  Approximately 77% of our plant facilities’ gross margins, orrevenues at the plants less product purchases, for the month of March 2003resulted from percentage-of-proceeds agreements in which we are typicallyresponsible for the marketing of the gas and NGLs. We pay producers a specifiedpercentage of the net proceeds received from the sale of the gas and the NGLs.

 

9

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Approximately 19% of ourplant facilities’ gross margins for the month of March 2003 resulted fromcontracts that are primarily fee-based from which we receive a set fee for eachMcf of gas gathered and/or processed. This type of contract provides us with asteady revenue stream that is not dependent on commodity prices, except to theextent that low prices may cause a producer to delay drilling.

 

Approximately 4% of ourplant facilities’ gross margins for the month of March 2003 resulted fromcontracts that combine gathering, compression or processing fees with‘‘keepwhole’’ arrangements or wellhead purchase contracts. Typically, we chargeproducers a gathering and compression fee based upon volume. In addition, weretain the NGLs recovered by the processing facility and keep the producerswhole by returning to the producers at the tailgate of the plant an amount ofresidue gas equal on a Btu basis to the natural gas received at the plantinlet. The ‘‘keepwhole’’ component of the contracts permits us to benefit whenthe value of the NGLs is greater as a liquid than as a portion of the residuegas stream. However, we are adversely affected when the value of the NGLs islower as a liquid than as a portion of the residue gas stream.

 

***Exploration and Production.***  The activities of the Exploration andProduction segment include the exploration and development of gas propertiesprimarily in the Rocky Mountain basins including those where our gatheringand/or processing facilities are located. The Marketing segment sells the majority of the production from theseproperties.

 

***Marketing.***  Our Marketing segment buys and sells gas andNGLs in the United States and Canada from and to a variety of customers.  The marketing of products purchased fromthird-parties typically results in low operating margins relative to the salesprice.   In addition, this segment also marketsgas and NGLs produced by our gathering, processing, treating and productionassets.  Also included in this segmentare our Canadian marketing operations (which are immaterial for separatepresentation).  In this segment,revenues for sales of product are recognized at the time the gas or NGLs aredelivered to the customer and are sensitive to changes in the market prices ofthe underlying commodities.  We sell ourproducts under agreements with varying terms and conditions in order to matchseasonal and other changes in demand. Our gas sales contracts have an average duration of 15 months.  

 

***Transportation.***  The Transportation segment reflects theoperations of Western’s MIGC and MGTC pipelines.  The majority of the revenue presented in this segment is derivedfrom transportation of residue gas for our Marketing segment and otherthird-parties.  In this segment, werealize revenue on a monthly basis from firm capacity contracts under which theshipper pays for transport capacity whether or not the capacity is used andfrom interruptible contracts where a fee is charged based upon volumes receivedinto the pipeline.  The Transportationsegments’ firm capacity contracts range in duration from one month to sixyears.

 

The following table setsforth our segment information as of and for the two quarters ended March 31,2003 and 2002 (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.

 
|                                              |   | **Gas Gathering  and  Processing** |        | **Exploration  and  Production** |       | **Marketing** |       | **Trans-  portation** |        | **Corporate** |       | **Eliminating  Entries** |       | **Total**   |        |
|---------------------------------------------------|--------|------------------------------------|-------------|----------------------------------|------------|---------------|------------|-----------------------|-------------|---------------|------------|--------------------------|------------|-------------|-------------|
| **Quarter Ended March 31,  2003**                 |   |                               | ** **  |                             | ** ** |          | ** ** |                  | ** **  |          | ** ** |                     | ** ** |        | ** **  |
| Revenues  from unaffiliated customers             |   |                               |        |                             |       |          |       |                  |        |          |       |                     |       |        |        |
| Sale  of gas                                      |   | $                                  | 1,073       |                             | $          | (283          | )          | $                     | 786,412     |          | $          | 296                      |       | $           | —      |   | $ | — |   | $ | 787,498 |   |
| Sale  of natural gas liquids                      |   | 4                                  |        | —                           |       | 96,937        |       | —                |        |          |       |                     |       | 96,941      |        |
| Equity  hedges:                                   |   |                               |        |                             |       |          |       |                  |        |          |       |                     |       |        |        |
| Residue                                           |   | (968                               | )           | (6,791                           | )          | —        |       | —                |        | —        |       | —                   |       | (7,759      | )           |
| Liquids                                           |   | (4,892                             | )           | —                           |       | —        |       | —                |        | —        |       | —                   |       | (4,892      | )           |
| Gathering,  processing and transportation revenue |   | 17,904                             |        | —                           |       | —        |       | 1,838                 |        | 35            |       | —                   |       | 19,777      |        |
| Total  revenues from unaffiliated customers       |   | 13,121                             |        | (7,074                           | )          | 883,349       |       | 2,134                 |        | 35            |       | —                   |       | 891,565     |        |
| Inter-segment  sales                              |   | 301,769                            |        | 64,544                           |       | 11,031        |       | 3,875                 |        | 34            |       | (381,253                 | )          | —      |        |
| Non-cash  change in fair value of derivatives     |   | (724                               | )           | (2,098                           | )          | (1,341        | )          | —                |        | —        |       | —                   |       | (4,163      | )           |
| Interest  income                                  |   | —                             |        | 8                                |       | —        |       | 2                     |        | 2,422         |       | (2,349                   | )          | 83          |        |
| Other,  net                                       |   | 431                                |        | 29                               |       | —        |       | —                |        | 161           |       | —                   |       | 621         |        |
| Total  revenues                                   |   | 314,597                            |        | 55,409                           |       | 893,039       |       | 6,011                 |        | 2,652         |       | (383,602                 | )          | 888,106     |        |
| Product  purchases                                |   | 264,348                            |        | 394                              |       | 877,928       |       | —                |        | 132           |       | (371,200                 | )          | 771,602     |        |
| Plant  operating and transportation expense       |   | 19,974                             |        | 178                              |       | 80            |       | 1,965                 |        | 531           |       | (806                     | )          | 21,922      |        |
| Oil  and gas exploration and production expense   |   | —                             |        | 21,561                           |       | —        |       | —                |        | —        |       | (9,050                   | )          | 12,511      |        |
| Earnings  from equity investments                 |   | (1,562                             | )           | —                           |       | —        |       | —                |        | —        |       | —                   |       | (1,562      | )           |
| Operating  profit                                 |   | 31,837                             |        | 33,276                           |       | 15,031        |       | 4,046                 |        | 1,989         |       | (2,546                   | )          | 83,633      |        |
|                                              |   |                               |        |                             |       |          |       |                  |        |          |       |                     |       |        |        |
| Depreciation,  depletion and amortization         |   | 7,895                              |        | 8,060                            |       | 35            |       | 433                   |        | 1,720         |       | —                   |       | 18,143      |        |
| Selling  and administrative expense               |   | 4,735                              |        | 3,241                            |       | 2,055         |       | 561                   |        | —        |       | —                   |       | 10,592      |        |
| (Gain)  loss from sale of assets                  |   | (92                                | )           | —                           |       | —        |       | —                |        | 373           |       | —                   |       | 281         |        |
| Interest  expense                                 |   | —                             |        | —                           |       | —        |       | —                |        | 6,814         |       | —                   |       | 6,814       |        |
| Segment  profit                                   |   | $                                  | 19,299      |                             | $          | 21,975        |       | $                     | 12,941      |          | $          | 3,052                    |       | $           | (6,918      | ) | $ | (2,546 | ) | $ | 47,803 |   |
|                                              |   |                               | ** **  |                             | ** ** |          | ** ** |                  | ** **  |          | ** ** |                     | ** ** |        | ** **  |
| **Identifiable assets**                           |   |                               | ** **  |                             | ** ** |          | ** ** |                  | ** **  |          | ** ** |                     | ** ** |        | ** **  |
| **Other allocated assets**                        |   | **$**                              | **(2,215**  | **)**                            | **$**      | **3,424**     | ** ** | **$**                 | **107,202** | ** **    | **$**      | **1,306**                | ** ** | **$**       | **478,446** | ** ** | **$** | **(51,330** | **)** | **$** | **536,833** | ** ** |
| **Investment in others**                          |   | **2,914**                          | ** **  | **—**                       | ** ** | **—**    | ** ** | **3,731**             | ** **  | **53,714**    | ** ** | **(36,174**              | **)**      | **24,185**  | ** **  |
| **Capital assets**                                |   | **587,781**                        | ** **  | **225,487**                      | ** ** | **1,637**     | ** ** | **42,142**            | ** **  | **54,432**    | ** ** | **7**                    | ** ** | **911,572** | ** **  |
| **Total identifiable assets**                     |   | **$**                              | **588,480** | ** **                       | **$**      | **228,911**   | ** ** | **$**                 | **108,839** | ** **    | **$**      | **47,179**               | ** ** | **$**       | **586,592** | ** ** | **$** | **(87,497** | **)** | **$** | **1,472,590** | ** ** |

 

10

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|                                              |   | **Gas  Gathering  and  Processing** |        | **Exploration  and  Production** |       | **Marketing** |       | **Trans-  portation** |        | **Corporate** |       | **Eliminating  Entries** |       | **Total**   |        |
|---------------------------------------------------|--------|-------------------------------------|-------------|----------------------------------|------------|---------------|------------|-----------------------|-------------|---------------|------------|--------------------------|------------|-------------|-------------|
| **Quarter Ended March 31,  2002**                 |   |                                | ** **  |                             | ** ** |          | ** ** |                  | ** **  |          | ** ** |                     | ** ** |        | ** **  |
| Revenues  from unaffiliated customers             |   |                                |        |                             |       |          |       |                  |        |          |       |                     |       |        |        |
| Sale  of gas                                      |   | $                                   | 315         |                             | $          | 252           |       | $                     | 534,383     |          | $          | 520                      |       | $           | —      |   | $ | — |   | $ | 535,470 |   |
| Sale  of natural gas liquids                      |   | 3                                   |        | —                           |       | 65,446        |       | —                |        | —        |       | —                   |       | 65,449      |        |
| Equity  hedges:                                   |   |                                |        |                             |       |          |       |                  |        |          |       |                     |       |        |        |
| Residue                                           |   | 1,698                               |        | 8,421                            |       | —        |       | —                |        | —        |       | —                   |       | 10,119      |        |
| Liquids                                           |   | (642                                | )           | —                           |       | —        |       | —                |        | —        |       | —                   |       | (642        | )           |
| Gathering,  processing and transportation revenue |   | 13,173                              |        | —                           |       | —        |       | 2,259                 |        | (1            | )          | —                   |       | 15,431      |        |
| Total  revenues from unaffiliated customers       |   | 14,547                              |        | 8,673                            |       | 599,829       |       | 2,779                 |        | (1            | )          | —                   |       | 625,827     |        |
| Inter-segment  sales                              |   | 121,330                             |        | 19,813                           |       | 3,560         |       | 4,129                 |        | 14            |       | (148,846                 | )          | —      |        |
| Non-cash  change in fair value of derivatives     |   | —                              |        | —                           |       | (10,995       | )          | —                |        | —        |       | —                   |       | (10,995     | )           |
| Interest  income                                  |   | —                              |        | 10                               |       | —        |       | —                |        | 1,827         |       | (1,800                   | )          | 37          |        |
| Other,  net                                       |   | 775                                 |        | (17                              | )          | —        |       | 12                    |        | 276           |       | —                   |       | 1,046       |        |
| Total  revenues                                   |   | 136,652                             |        | 28,479                           |       | 592,394       |       | 6,920                 |        | 2,116         |       | (150,646                 | )          | 615,915     |        |
| Product  purchases                                |   | 102,297                             |        | 525                              |       | 584,370       |       | —                |        | 322           |       | (142,908                 | )          | 544,606     |        |
| Plant  operating and transportation expense       |   | 16,425                              |        | 56                               |       | 53            |       | 2,615                 |        | —        |       | (278                     | )          | 18,871      |        |
| Oil  and gas exploration and production expense   |   | —                              |        | 13,046                           |       | —        |       | —                |        | —        |       | (5,657                   | )          | 7,389       |        |
| Earnings  from equity investments                 |   | (851                                | )           | —                           |       | —        |       | —                |        | —        |       | —                   |       | (851        | )           |
| Operating  profit                                 |   | 18,781                              |        | 14,852                           |       | 7,971         |       | 4,305                 |        | 1,794         |       | (1,803                   | )          | 45,900      |        |
|                                              |   |                                |        |                             |       |          |       |                  |        |          |       |                     |       |        |        |
| Depreciation,  depletion and amortization         |   | 10,596                              |        | 5,321                            |       | 40            |       | 435                   |        | 1,554         |       | —                   |       | 17,946      |        |
| Selling  and administrative expense               |   | 3,841                               |        | 2,364                            |       | 1,773         |       | 713                   |        | —        |       | —                   |       | 8,691       |        |
| Loss  from sale of assets                         |   | 3                                   |        | —                           |       | —        |       | 6                     |        | —        |       | —                   |       | 9           |        |
| Interest  expense                                 |   | —                              |        | —                           |       | —        |       | —                |        | 8,460         |       | (1,800                   | )          | 6,660       |        |
| Segment  profit                                   |   | $                                   | 4,341       |                             | $          | 7,167         |       | $                     | 6,158       |          | $          | 3,151                    |       | $           | (8,220      | ) | $ | (3 | ) | $ | 12,594 |   |
|                                              |   |                                | ** **  |                             | ** ** |          | ** ** |                  | ** **  |          | ** ** |                     | ** ** |        | ** **  |
| **Identifiable assets**                           |   |                                | ** **  |                             | ** ** |          | ** ** |                  | ** **  |          | ** ** |                     | ** ** |        | ** **  |
| **Other allocated assets**                        |   | **$**                               | **8,001**   | ** **                       | **$**      | **6,169**     | ** ** | **$**                 | **98,528**  | ** **    | **$**      | **1,111**                | ** ** | **$**       | **306,023** | ** ** | **$** | **(56,275** | **)** | **$** | **363,557** | ** ** |
| **Investment in others**                          |   | **1,863**                           | ** **  | **—**                       | ** ** | **—**    | ** ** | **3,660**             | ** **  | **44,529**    | ** ** | **(37,637**              | **)**      | **12,415**  | ** **  |
| **Capital assets**                                |   | **571,230**                         | ** **  | **191,215**                      | ** ** | **1,790**     | ** ** | **42,833**            | ** **  | **52,924**    | ** ** | **—**               | ** ** | **859,992** | ** **  |
| **Total identifiable assets**                     |   | **$**                               | **581,094** | ** **                       | **$**      | **197,  384** | ** ** | **$**                 | **100,318** | ** **    | **$**      | **47,604**               | ** ** | **$**       | **403,476** | ** ** | **$** | **(93,912** | **)** | **$** | **1,235,964** | ** ** |

 

11

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***LEGAL PROCEEDINGS***

 

Referenceis made to “Part II - Other Information - Item 1. Legal Proceedings,” of thisForm 10-Q.

*** ***

##### ***RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS***

##### *** ***

In April 2002, the FASB issued SFAS No. 145,“Rescission of FAS Statements No. 4, 44 and 64, Amendment of FAS Statement No. 13, and Technical Corrections,” which isgenerally effective for fiscal years beginning after May 15, 2002.  Through the rescission of SFAS Statements 4and 64, SFAS No. 145 eliminates the requirement that gains and losses fromextinguishment of debt be aggregated and, if material, be classified as an extraordinaryitem net of any income tax effect.  SFASNo. 145 made several other technical corrections to existing pronouncementsthat may change accounting practice.  Weadopted SFAS No. 145 on January 1, 2003. The adoption of this pronouncement did not have an impact on ourearnings or financial position aswe had no gains and losses from extinguishment of debt in the first quarter of2003.

 

In June 2002, the FASB issued SFAS No. 146,“Accounting for Costs Associated with Exit or Disposal Activities.”  SFAS No. 146 is effective for exit or disposalactivities that are initiated after December 31, 2002.  This statement addresses financialaccounting and reporting for costs associated with exit or disposal activitiesand nullifies Emerging Issues Task Force, or EITF, Issue No. 94-3, “LiabilityRecognition for Certain Employee Termination Benefits and Other Costs to Exitan Activity  (including Certain CostsIncurred in a Restructuring).”   Weadopted SFAS No. 146 on January 1, 2003. The adoption of this pronouncement did not have an impact on our earningsor financial position for the first quarter of 2003.

 

In November 2002, the FASB issued Interpretation No.45, or “FIN 45”, “Guarantor’s Accounting and Disclosure Requirements forGuarantees, Including Indirect Guarantees of Indebtedness of Others.” FIN 45requires that a liability be recorded in the guarantor’s balance sheet uponissuance of a guarantee. FIN 45 also requires additional disclosures about theguarantees an entity has issued. We adopted FIN 45 on January 1, 2003.  The adoption of this pronouncement did not have an impact on ourearnings or financial position in the first quarter of 2003.

 

In January 2003, the FASB issued Interpretation No.46, or “FIN 46”, “Consolidation of Variable Interest Entities.”  FIN 46 provides guidance on how to identifya variable interest entity, or VIE, and determine when the assets, liabilities,and results of operations of a VIE need to be included in a company’sconsolidated financial statements.  FIN46 also requires additional disclosures by primary beneficiaries and othersignificant variable interest holders in a VIE.  The provisions of FIN 46 are effective immediately for all VIEscreated after January 31, 2003.  ForVIEs created before February 1, 2003, the provisions of FIN 46 must be adoptedat the beginning of the first interim or annual reporting period beginningafter June 15, 2003.   We do not have aninterest in any VIEs and therefore the adoption of this pronouncement did not have an impact on our earnings orfinancial position.

 

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

 

The following discussion and analysis relates tofactors that have affected our consolidated financial condition and results ofoperations for the three months ended March 31, 2003 and 2002.  Certain prior year amounts have beenreclassified to conform to the presentation used in 2003.  You should also refer to our interimconsolidated financial statements and notes thereto included elsewhere in thisdocument.  This section, as well asother sections in this Form 10-Q, contain “forward-looking statements” withinthe meaning of the Private Securities Litigation Reform Act of 1995, which canbe identified by the use of forward-looking terminology, such as “may,”“intend,” “will,” “expect,” “anticipate,” “estimate,” or “continue” or thenegative thereof or other variations thereon or comparable terminology.  In addition to the important factorsreferred to herein, numerous factors affecting the gas processing industrygenerally and in the specific markets for gas and NGLs in which we operatecould cause actual results to differ materially from those in suchforward-looking statements.

 

***RESULTS OF OPERATIONS***

 

**Three months ended March 31, 2003 compared to the threemonths ended March 31, 2002**

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

 
|                                        |   | **Three  Months Ended  March 31,** |       | **Percent** |       |
|---------------------------------------------|--------|------------------------------------|------------|-------------|------------|
|                                        |   | **2003**                           |       | **2002**    |       | **Change** |   |
| **Financial  results:**                     |   |                               | ** ** |        | ** ** |   | ** ** |
| Revenues                                    |   | $                                  | 888,106    |        | $          | 615,915 |   | 44 |   |
| Gross  profit                               |   | 65,490                             |       | 27,954      |       | 134 |   |
| Net  income                                 |   | 23,375                             |       | 8,000       |       | 192 |   |
| Earnings  per share of common stock         |   | 0.65                               |       | 0.18        |       | 261 |   |
| Earnings  per share of common stock-diluted |   | 0.63                               |       | 0.18        |       | 250 |   |
| Net  cash provided by operating activities  |   | $                                  | 115,155    |        | $          | 22,525 |   | 411 |   |
|                                        |   |                               |       |        |       |   |   |
| **Operating  data:**                        |   |                               |       |        |       |   |   |
| Average  gas sales (MMcf/D)                 |   | 1,593                              |       | 2,445       |       | (35 | ) |
| Average  NGL sales (MGal/D)                 |   | 1,655                              |       | 1,940       |       | (15 | ) |
| Average gas prices ($/Mcf)                  |   | $                                  | 5.44       |        | $          | 2.47 |   | (65 | ) |
| Average NGL prices ($/Gal)                  |   | $                                  | 0.62       |        | $          | 0.37 |   | (41 | ) |

 

Net income increased $15.4million for the three months ended March 31, 2003 compared to the same periodin 2002.  The increase in net income wasprimarily attributable to a significant increase in gas and NGL prices in thefirst quarter of 2003 compared to the same period last year.  This increase in prices was supplemented byincreased equity production from the Powder River Basin coal bed methanedevelopment and the Green River Basin. Also contributing to the increase in net income was a pre-tax $7.1million increase in operating income from our marketing operations in the threemonths ended March 31, 2003 compared to the same period in 2002.  Partially offsetting the increases to netincome in the three months ended March 31, 2003 was a pre-tax loss of $2.8million from the discontinuance of hedge treatment on some financialinstruments and included a $6.7 million after-tax loss from the Cumulative effect of a change inaccounting principle from the adoption of SFAS No. 143 “Accounting forAsset Retirement Obligations” on January 1, 2003.

 

Revenues from the sale of gas increased $234.2 millionto $779.7 million for the three months ended March 31, 2003 compared to thesame period in 2002.  This increase wasprimarily due to an increase in product prices, which more than offset adecrease in sales volume in the three months ended March 31, 2003.  Average gas prices realized by us increased$2.97 per Mcf to $5.44 per Mcf for the quarter ended March 31, 2003 compared tothe same period in 2002.  Included inthe realized gas price were approximately $7.8 million of losses recognized inthe three months ended March 31, 2003 related to futures positions on equitygas volumes.  We have entered intoadditional futures positions for approximately half of our equity gas for theremainder of 2003.  See furtherdiscussion in “Item 3. Quantitative and Qualitative Disclosures About MarketRisk”.  Average gas sales volumes decreasedto 1,593 MMcf per day for the quarter ended March 31, 2003 compared to the sameperiod in 2002.  This decrease was dueto a temporary reduction in third party sales volume resulting from theincrease in product prices and related credit exposure.

 

Revenues from the sale of NGLs increased approximately$27.2 million to $92.0 million for the three months ended March 31, 2003compared to the same period in 2002. This increase is primarily due to a significant increase

 

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in product prices,which was partially offset by a reduction in sales volumes as a result of thesale of our Toca facility in September 2002. Average NGL prices realized by us increased $0.25 per gallon to $0.62per gallon for the three months ended March 31, 2003 compared to the sameperiod in 2002.  Included in therealized NGL price were approximately $4.9 million of losses recognized in thethree months ended March 31, 2003 related to futures positions on equity NGLvolumes.  We have entered intoadditional futures positions for the majority of our equity NGL production forthe remainder of 2003.  See furtherdiscussion in “Item 3. Quantitative and Qualitative Disclosures About MarketRisk”.  Average NGL sales volumesdecreased 285 MGal per day to 1,655 MGal per day for the three months endedMarch 31, 2003 compared to the same period in 2002.

 

Product purchases increased by $227.0 million for thequarter ended March 31, 2003 compared to the same period in 2002 as a result ofthe significant increase in commodity prices. Overall, combined product purchases as a percentage of sales of allproducts decreased to 87% in the first quarter of 2003 from 89% in the firstquarter of 2002.  The reduction in thispercentage is primarily the result of an increase in product prices, an increaseof sale of our equity production and increased marketing margins.

 

Marketing margins on residue gasaveraged $0.10 per Mcf for the quarter ended March 31, 2003 compared to $0.02per Mcf in the same period of 2002.  Theincrease in margin in the 2003 quarter primarily resulted from transactionsassociated with our firm transportation capacity from the Rocky Mountain regionto the mid-continent.  There is no assurance, however, that these marketconditions for our gas and NGL products and related margins will continue inthe future, that we will be in a similar position to benefit from them or thatwe will continue to originate the same amount of transactions in futurequarters.

 

Plant and transportation operating expense increasedby $3.1 million for the three months ended March 31, 2003 compared to the sameperiod in 2002.  This increase wasprimarily due to additional leased compression in the Powder River Basin coalbed development and higher utility and fuel charges at our plant facilities.  Also contributing to the increase are feespaid for gathering services on our 50%-owned Rendezvous Gas Services, L.L.C.,or Rendezvous.  This investment isaccounted for under the equity method and our share of revenues is reflected inEarnings from equity investments.

 

Oil and gas exploration and production expensesincreased by $5.1 million for the three months ended March 31, 2003 compared tothe same period in 2002.  In ouroperating areas, the significant increase in residue gas prices in 2003resulted in substantially higher severance tax expenses.  This increase was partially offset bydecreased lease operating expenses, or LOE, in the Powder River Basin coal beddevelopment.   Overall, LOE averaged$0.35 per Mcf for the three months ended March 31, 2003 and LOE in the PowderRiver Basin coal bed development averaged $0.37 per Mcf for the three monthsended March 31, 2003.  This representsdecreases of $0.04 per Mcf from the same periods in 2002.  The decreases in LOE are substantially dueto increased production volumes in the first quarter of 2003.

 

Selling and administrative expenses increased by $1.9million for the three months ended March 31, 2003 as compared to the sameperiod in 2002, due to higher health insurance costs and higher compensationexpenses.

##### *** ***

##### ***Depreciation, depletion and amortization increased by$197,000 for the three months ended March 31, 2003 as compared to the sameperiod in 2002.  This increase is theresult of additional capital expenditures and depletion on our oil and gasassets that was substantially offset by revisions to the operating lives andsalvage values of our operating assets. These revisions were the result of analysis performed in connection withthe adoption of SFAS No. 143.***

     

##### *** ***In the first quarter of 2003, in order to properlyalign our hedged volumes of natural gas to our forecasted equity production for2003, we discontinued hedge treatment on financial instruments for 10 MMcf perday of natural gas and 50,000 Barrels per month of ethane. As a result, apre-tax loss of $2.8 million was reclassified into earnings in the three monthsended March 31, 2003 from Accumulated other comprehensive income.  

 

***Cash FlowInformation***

 

Cash flows from operatingactivities increased by $92.6 million for the three months ended March 31, 2003compared to same period in 2002.  Thisincrease was primarily due to an increase in net income in the 2003 periodcompared to the prior year, the liquidation of product inventory positions andthe timing of cash receipts and payments.

 

Cash flows used in investingactivities increased by $25.5 million for the three months ended March 31, 2003compared to the same period in 2002. This increase was primarily due to the acquisition of several gatheringsystems, which closed January 31, 2003.

 

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Cash flows used in financing activities increased by$57.5 million for the three months ended March 31, 2003 compared to the sameperiod in 2002.  This increase wasprimarily due to an increase in net income in the 2003 period compared to theprior year and the liquidation of product inventory positions.

 

***Other Information***

 

***Acquisition of Gathering Systems.***  Effective February 1, 2003, we acquired 18gathering systems in Wyoming, primarily located in the Green River Basin withsmaller operations in the Powder River and Wind River Basins, for a total of$37.1 million.  These assets wereacquired from El Paso Field Services and related entities.  These systems are comprised of a total of550 miles of gathering lines and, in March 2003, were gathering an average of133 MMcf per day.  Approximately 80% ofthe revenues to be derived from these facilities will be earned underlong-term, fee-based contracts with the remaining revenue generated underkeep-whole arrangements.  The threelargest systems are located in the Wamsutter area of the Greater Green RiverBasin.  Four of these systems arelocated in the Wind River Basin and provide us with the opportunity to expandour gathering and processing activities into an area in which we have notpreviously operated.  Several of thesesystems are located in the Powder River Basin, do not integrate directly intoour existing systems and will likely be disposed of.  These systems are classified as Assets held for sale on theConsolidated Balance Sheet at March 31, 2003. During the first quarter of 2003, these facilities, which are includedin Assets held for sale, generated net after-tax earnings of approximately$94,000, or $0.00 per share of common stock. We believe the results from these facilities are immaterial for separatepresentation as a discontinued operation.

 

#### ***Critical Accounting Policies***

 

Theapplication of accounting policies is an important process that has developedas our business activities have evolved and as accounting rules havedeveloped.   Accounting rules generallydo not involve a selection among alternatives, but involve an interpretationand implementation of existing rules, and the use of judgment, to the specificset of circumstances existing in our business. We make every effort to properly comply with all applicable rules on orbefore their adoption, and we believe the proper implementation and consistentapplication of the accounting rules is critical.  Our critical accounting policies and estimates are discussedbelow.

 

***Use of Estimates. ***The preparation of consolidated financialstatements in conformity with generally accepted accounting principles requiresus to make estimates and assumptions that affect the amounts reported forassets and liabilities, the disclosure of contingent assets and liabilities atthe date of the financial statements, and the amounts reported for revenues andexpenses during the reporting period. These estimates are evaluated on an ongoing basis, utilizing historicalexperience, consultation with experts and other methods considered reasonablein the particular circumstances. However, actual results may differ significantly from the estimatesused.  Any effects on our business, financialposition or results of operations resulting from revisions to these estimateswill be recorded in the period in which the facts that necessitate a revisionbecome known.

 

***Property and Equipment. *** Our property and equipment is recorded at thelower of cost, including capitalized interest, or estimated realizablevalue.  Interest incurred during theconstruction period of new projects is capitalized and amortized over the lifeof the associated assets.

 

##### ***Depreciation on these assets is provided using the straight-line methodbased on the estimated useful life of each facility, which ranges from three to35 years.  Useful lives are determinedbased on the shorter of our estimate of the life of the equipment or ourestimate of the reserves serviced by the equipment.  Among other factors, the estimates consider our experience with similarassets and technical analysis of the reserves. The cost of acquired gas purchase contracts is amortized using thestraight-line method or units of production. If the actual lives of the equipment or the reserves serviced by theequipment were less than we originally estimated, we may be required to recorda loss upon retirement of a specific asset.***

##### *** ***

##### ***In connection with the adoption of SFAS No. 143, wecompleted a review of our operating assets and reevaluated the operating lifeand salvage values of the associated equipment. ***As a result of this evaluation, weextended the useful life of many of our operating assets and adjusted theestimated salvage value of our operating equipment.  These adjustments resulted in an approximate $2.5 million, or $0.04per share of commonstock - assuming dilution, decrease in depreciation, depletion and amortization in thethree months ended March 31, 2003 from the expense calculated using theprevious useful lives.  The adjustmentsto the salvage value and depreciable lives of our assets are treated as arevision of an estimate and will be accounted for on a prospective basis.

 

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***Oil and Gas Properties and Equipment. *** We follow the successful efforts method ofaccounting for oil and gas exploration and production activities.  Acquisition costs, development costs andsuccessful exploration costs are capitalized when incurred.  Exploratory dry hole costs, lease rentalsand geological and geophysical costs are charged to expense as incurred. Uponsurrender of undeveloped properties, the original cost is charged againstincome.  Producing properties andrelated equipment are depleted and depreciated by the units of production methodbased on estimated proved reserves.  Theunits of production method is sensitive to the determination of provedreserves.  We utilize technical analysisand outside expertise annually to determine the reserves associated with ouroil and gas properties.   To the extentthe reserves are modified based on this review, the depletion determined underthe units of production method will be increased or decreased on a prospectivebasis.

 

***Impairment of Long-Lived Assets.*** If changes in the expected performance of anasset occur, or if overall economic conditions warrant, we will review ourassets to determine their economic viability. This review is completed at the plant facility, the related group ofplant facilities or the oil and gas producing property level.  In order to determine whether an impairmentexists, we compare the net book value of the asset to the estimated fair marketvalue or the undiscounted expected future net cash flows, determined byapplying future prices estimated by management over the shorter of the lives ofthe facilities or the reserves supporting the facilities.  If an impairment exists, write-downs ofassets are based upon expected future net cash flows discounted using aninterest rate commensurate with the risk associated with the underlyingasset.  This analysis is sensitive to,among other things, management’s expectation of commodity prices, operatingcosts, drilling plans and production rates.

 

***Identification of Derivatives and Mark toMarket Valuations****. *Thedetermination of which contractual instruments meet the definition of aderivative under accounting rules is subject to differing interpretations as isthe valuation of those derivatives. Management uses its judgment to analyze all contracts to determinewhether or not they qualify as derivatives and to determine their value.  Specific areas in which management’sjudgment is required includes identifying contracts meeting the criteria forexclusions from derivatives treatment, market liquidity, and market valuation.   This analysis is sensitive to commodityprices, outside market factors and management’s intent upon entering into thesecontracts.

 

***Significant Risks****.*  We are subject to anumber of risks inherent in the industry in which we operate, including pricevolatility, counterparty credit risk, the success of our drilling programs andother gas supply.  Our financialcondition and results of operations will depend significantly upon the priceswe receive for gas and NGLs.  These pricesare subject to fluctuations in response to changes in supply and demand and avariety of additional factors that are beyond our control.  In addition, we must continually connect newwells to our gathering systems in order to maintain or increase throughputlevels to offset natural declines in dedicated volumes.  The number of new wells drilled will dependupon, among other factors, prices for gas and oil, the drilling budgets ofthird-party producers, the energy policy of the federal government and theavailability of foreign oil and gas, none of which are within our control.

 

***Recently Issued Accounting Pronouncements.***  We continually monitor and revise ouraccounting policies as new rules are issued. At this time, there are several new accounting pronouncements that haverecently been issued, but not yet adopted, which will have an impact on ouraccounting when these rules become effective later in 2003.

 

#### ***Liquidity andCapital Resources***

 

Our sources of liquidity and capital resourceshistorically have been net cash provided by operating activities, fundsavailable under our financing facilities and proceeds from offerings of debtand equity securities.  In the past,these sources have been sufficient to meet our needs and finance the growth ofour business.  We can give no assurancethat the historical sources of liquidity and capital resources will beavailable for future development and acquisition projects, and we may berequired to seek additional or alternative financing sources.  Product prices, sales of inventory, thevolumes of natural gas processed by our facilities, the volume of natural gasproduced from our producing properties, the margin on third-party productpurchased for resale, as well as the timely collection of our receivables willall affect future net cash provided by operating activities.  Additionally, our future growth will bedependent upon obtaining additions to dedicated plant reserves, acquisitions,new project development, marketing results, efficient operation of ourfacilities and our ability to obtain financing at favorable terms.

 

During the past severalyears, although some of our plants have experienced declines in dedicatedreserves, overall we have been successful in connecting additional reserves tomore than offset the natural declines. The overall level of drilling 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

 

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and regulation by governmental agencies, and the availability offoreign oil and gas, none of which is within our control. There is no assurancethat we will continue to be suc­cessful in replacing the dedicated reservesprocessed at our facilities.  Anyprolonged reduction in prices for natural gas and NGLs may depress the levelsof exploration, development and production by third-parties and us.  Lower levels of these activities couldresult in a corresponding decline in the demand for our gathering, processingand treating services.  A reduction inany of these activities could have a material adverse effect on our financialcondition and results of operations.

 

We believe that theamounts available to be borrowed under the revolving credit facility, togetherwith net cash provided by operating activities, will provide us with sufficientfunds to connect new reserves, maintain our existing facilities and completeour current capital expenditure program. Depending on the timing and the amount of our future projects, we may berequired to seek additional sources of capital.  Our ability to secure such capital is restricted by our financingfacilities, although we may request additional borrowing capacity from ourlenders, seek waivers from our lenders to permit us to borrow funds fromthird-parties, seek replacement financing facilities from other lenders, usestock as a currency for acquisitions, sell existing assets or a combination ofalternatives.  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.  We also believe that cashprovided by operating activities and amounts available under the revolving creditfacility will be sufficient to meet scheduled principal repayments during 2003of $43.3 million under the Master Shelf Agreement and our preferred stockdividend requirements during the remainder of 2003 of approximately $5.4million.

 

We have effective shelfregistration statements filed with the SEC for an aggregate of $200 million ofdebt securities and preferred stock, along with the shares of common stock, ifany, into which those securities are convertible, and $62 million of debtsecurities, preferred stock or common stock. These shelf registrations allow us to access the debt and equity marketswithout the requirement of further SEC review.

 

Our sources and uses offunds for the three months ended March 31, 2003 are summarized as follows(dollars in thousands):

 

**Sources of funds:**

 
| Borrowings  under the revolving credit facility          |   | $       | 316,700 |   |
|----------------------------------------------------------|--------|---------|---------|--------|
| Borrowings  under the Master Shelf Agreement             |   | 25,000  |    |
| Proceeds from the dispositions of property and equipment |   | 41      |    |
| Net  cash provided by operating activities               |   | 115,155 |    |
| Proceeds  from exercise of common stock options          |   | 1,415   |    |
| Total  sources of funds                                  |   | $       | 458,311 |   |

 

**Uses of funds:**

 
| Payments  related to long-term debt (including debt issue costs) |   | $      | 391,895 |   |
|------------------------------------------------------------------|--------|--------|---------|--------|
| Capital  expenditures                                            |   | 57,076 |    |
| Preferred  dividends paid                                        |   | 1,811  |    |
| Common  dividends paid                                           |   | 1,653  |    |
| Total  uses of funds                                             |   | $      | 452,435 |   |

 

##### ***CapitalInvestment Program. ***Our capital expenditures during the three monthsended March 31, 2003 totaled approximately $57.1 million. Overall, capital expenditures during this quarter consisted of thefollowing: (i) approximately $5.7 million related to gathering, processing,treating and pipeline assets, including $1.6 million for maintaining existing facilities;(ii) approximately $10.9 million related to exploration and production andlease acquisition activities; (iii) $37.1 million for the acquisition of 18gathering systems which closed in January 2003; (iv) approximately $2.1 million forinformation technology and other items; and (v) approximately $1.3 million forcapitalized overhead and interest. Overall, capital expenditures in the Powder River Basin coal bed methanedevelopment and in the Green River Basin in southwest Wyoming operationsrepresented 68% and 21%, respectively, of the total capital expenditures in the three monthsended March 31, 2003.

 

##### ***We anticipate capital expenditures in 2003 of approximately $187.3million.  The 2003 capital budgetconsists of the following: (i) approximately $58.2 million related togathering, processing, treating and pipeline assets, including $11.4 millionfor maintaining existing facilities; (ii) approximately $79.9 million relatedto exploration and production and lease acquisition activities; (iii) $37.1million for the acquisition of 18 gathering systems which closed in January2003; (iv) approximately $4.3 million for information technology and otheritems and (v) $7.8 million for capitalized interest and overhead.  Overall, capital expenditures in the PowderRiver Basin coal bed methane development and in southwest Wyoming operationsrepresent 36% and 47%, respectively, of the total 2003***

##### *** ***

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##### ***budget.  Due to drilling and regulatory uncertaintiesthat are beyond our control, we can make no assurance that our capital budgetfor 2003 will not change.  This budgetmay be further increased to provide for acquisitions if approved by our boardof directors.***

##### *** ***

##### ***ContractualCommitments and Obligations***

##### *** ***

***Contractual CashObligations.***  Asummary of our contractual cash obligations as of March 31, 2003 is as follows(dollars in thousands): 

 
|                                                   |   |                  |    | **Payments  by Period** |   |
|--------------------------------------------------------|--------|-----------------------|---------|-------------------------|--------|
| **Type of Obligation**                                 |   | **Total  Obligation** |    | **Due in  2003**        |   | **Due in  2004 - 2005** |   | **Due in  2006 - 2007** |   | **Due  Thereafter** |   |
| Guarantee  of Fort Union Project Financing             |   | $                     | 6,114   |                    | $      | 568 |   | $ | 1,669 |   | $ | 1,931 |   | $ | 1,946 |   |
| Operating  Leases                                      |   | 77,246                |    | 10,856                  |   | 23,002 |   | 21,983 |   | 21,405 |   |
| Firm  Transportation Capacity and Gathering Agreements |   | 250,512               |    | 22,838                  |   | 58,311 |   | 56,885 |   | 112,478 |   |
| Firm  Storage Capacity Agreements                      |   | 27,450                |    | 3,962                   |   | 7,672 |   | 5,365 |   | 10,451 |   |
| Long-term  Debt                                        |   | 309,834               |    | 43,334                  |   | 66,500 |   | 20,000 |   | 180,000 |   |
| Total  Contractual Cash Obligations                    |   | $                     | 671,156 |                    | $      | 81,558 |   | $ | 157,154 |   | $ | 106,164 |   | $ | 326,280 |   |

 

***Guarantee of FortUnion Project Financing.*** In 1998, we joined with other industry participants to form Fort UnionGas Gathering, L.L.C., or Fort Union, to construct a 106-mile long, 24-inchgathering pipeline and treater to gather and treat natural gas in the PowderRiver Basin in northeast Wyoming.  Weown a 13% equity interest in Fort Union and are the construction manager andfield operator.  Construction of thegathering header and treating system was project financed by Fort Union.  In 2001, an expansion of Fort Union wascompleted to increase capacity.  Theexpansion costs totaled approximately $22.0 million and were also projectfinanced by Fort Union.  This debt isamortizing on an annual basis and is scheduled to be fully paid in 2009.  All participants in Fort Union haveguaranteed Fort Union’s payment of the project financing on a proportionalbasis, resulting in our guarantee of $6.1 million of the debt of Fort Union atMarch 31, 2003.  This guarantee is notreflected on our Consolidated Balance Sheet.

** **

***OperatingLeases. ***In theordinary course of our business operations, we enter into operating leases foroffice space, office equipment, communication equipment and transportationequipment.  In addition, primarily tosupport our growing development in the Powder River coal bed development, wehave entered into operating leases for compression equipment.  Payments made on these leases are acomponent of operating expenses and are reflected on the Consolidated Statementof Operations and, as operating leases, are not reflected on our ConsolidatedBalance Sheet.  As of March 31, 2003, wehad leased a total of 122 compression units. These leases have terms ranging from two to ten years with return orfair market purchase options available at various times during the lease.   If we were to exercise the early buyoutoptions on all the leased equipment, these purchase options would require thecapital expenditure of approximately $33.9 million between 2007 and 2011.  At March 31, 2003, we had four compressorunits under an interim leasing agreement. These compressors will be added to the existing lease arrangements whenthe equipment is installed and in service.

 

In August 2002, we entered into a lease with a sevenyear and nine month term for approximately 85,000 square feet of office spacein Denver, Colorado.  The cumulativelease payments over the term of this agreement, which began upon occupancy,will total approximately $10.7 million. Our corporate offices were relocated to this space in March 2003.  We also entered into a ten-year agreement effectivein January 2003 for the lease of approximately 26,000 square feet of officespace in Gillette, Wyoming for our Wyoming field operations.  The cumulative lease payments over the termof this agreement will total approximately $3.0 million.

 

***Firm TransportationCapacity and Gathering Agreements.***  Accessto firm transportation is also a significant element of our businessstrategy.  Firm transportation ensuresthat our equity production has access to downstream markets and allows us tocapture incremental profit when pricing differentials between physicallocations occur.  As of March 31, 2003,we had contracts for approximately 632 MMcf per day of firmtransportation.  This amount representsour total contracted amount on many individual pipelines.  In many cases it is necessary to utilizesequential pipelines to deliver gas into a specific sales market. In total, wehave the capacity to transport 171 MMcf per day of gas from the Rocky Mountainarea to the Mid-Continent.  Thisutilizes a total of approximately 376 MMcf

 

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per day of firmcapacity on three separate pipelines.  The total rate under these long-term contracts to transport this gas tothe Mid-Continent approximates $0.35 per Mcf. Our remaining firm capacity consists of 136 MMcf per day to marketswithin the Rocky Mountains and 120 MMcf per day contracted in various othermarkets throughout the country.  Inaddition, we hold 83 MMcf per day of firm gathering capacity on the Fort Uniongathering line.

 

A portion of this firm transportation capacity wascontracted for use in our Marketing operations.  For example, our Marketing segment purchases gas in the RockyMountain region, transports this gas utilizing its 56 MMcf per day of our firmtransportation capacity to the Mid-Continent, and resells the gas to variousmarkets.  During the three months endedMarch 31, 2003, these types of transactions have been profitable as the pricedifference, or basis, between the Rocky Mountain and Mid-Continent regions hasexceeded the cost of transportation. Historically, to the extent these transportation contracts were acquiredfor our Marketing segment, they were derivative contracts as defined by SFASNo. 133 and were marked to market.  OnOctober 1, 2002, the Federal Energy Regulatory Commission’s, or FERC, policy oncapacity release expired.  After thatdate, companies are no longer able to re-market transportation capacity atrates which exceed the maximum allowable rate permitted by the pipelines’tariff.  On some pipelines, this reducesour ability to liquidate our position. Accordingly, as of October 1, 2002, the transportation contracts onthese specific pipelines are no longer considered derivatives under SFAS No.133 and were no longer marked to market.  We have elected to hedge the cash flows resulting from transactions utilizinga portion of this transportation capacity. To the extent of these hedges the transactions are classified as cashflow hedges.  In the future, we may,from time to time, hedge additional portions of this capacity and would utilizehedge accounting for the transactions.

 

We expect that the fixed fees associated with ourcontracts for firm transportation capacity during the remainder of 2003 willaverage approximately $0.18 per Mcf per day. The associated contract periods range from one month to fourteenyears.  Under firm transportationcontracts, we are required to pay the fees associated with these contractswhether or not the transportation is used.

 

***Firm StorageCapacity Agreements*.**  We customarily store gas in undergroundstorage facilities to ensure an adequate supply for long-term sales contractsand to capture seasonal price differentials. As of March 31, 2003, we had contracts in place for approximately 13.7Bcf of storage capacity at various third-party facilities.  The fees associated with these contractsduring the remainder of 2003 will average $0.29 per Mcf of annual capacity.  The associated contract periods have anaverage term of seventeen months.  AtMarch 31, 2003, we held gas in our contracted storage facilities and inimbalances of approximately 4.4 Bcf at an average cost of $2.56 per Mcf comparedto 9.0 Bcf at an average cost of $2.04 per Mcf at March 31, 2002.  These positions are for storage withdrawalswithin the next twelve months.  At thetime that we place product into storage, we contract for the sale of thatproduct, physically or financially, and do not speculate on the future value ofthe product.  We have also entered into a precedentagreement for 2.4 Bcf of annual capacity, for a term of ten years, forstorage in a facility, which is not yet completed.  We anticipate the completion of the construction of this facilityin 2004.  When the facility iscompleted, we will enter into a storage agreement.

 

#### **From time to time, we lease NGL storage space atmajor trading locations in order to store products for resale during periodswhen prices are favorable and to facilitate the distribution of products. AtMarch 31, 2003, we held NGLs in storage at various third-party facilities of2,772 MGal, consisting primarily of propane and normal butane, at an averagecost of $0.27 per gallon compared to 3,261 MGal at an average cost of $0.44 pergallon at March 31, 2002.**

 

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

 

***Revolving CreditFacility. ***AtMarch 31, 2003, $21.5 million was outstanding under our existing $250 millionrevolving credit facility.  On April 24,2003, we amended and restated our existing revolving credit facility.   Our new facility is with a syndicate ofbanks, which have extended to us a $300 million four-year revolving line ofcredit.  A portion of the borrowingsunder the new $300 million credit facility was used to repay the amountoutstanding under the $250 million predecessor credit agreement.

 

Loans made under the new facility are secured by apledge of the capital stock of our significant subsidiaries, and some of oursubsidiaries have also provided a guaranty of payments owed by us under thefacility.  The facility also contains aprovision that requires us to secure loans under the facility with 75% of ouroil and gas reserves.  This provisionwould only be triggered in the event of an issuance of or reduction to a debtrating on the revolving credit facility of Ba3 or lower by Moody’s InvestorsService, Inc., or Moody’s, or the issuance of or the reduction to a debt

 

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rating on therevolving credit facility of BB- or lower by Standard & Poor’s RatingServices, a division of The McGraw-Hill Companies, Inc., or S&P.

 

The borrowings under the new credit facility bearinterest at Eurodollar rates or a base rate, as requested by us, plus anapplicable percentage based on our debt to capitalization ratio.  The base rate is the higher of the FederalFunds Rate plus 0.005% or the agent’s published prime rate.  We also pay a quarterly facility fee rangingbetween 0.30% and 0.50%, depending on our debt to capitalization ratio.  This fee is paid on the totalcommitment.  At April 30, 2003, theinterest rate payable on borrowings under the new facility was approximately3.1%.

 

Under the new credit facility, we are subject to anumber of covenants, including: maintaining a total debt to capitalizationratio of not more than 55%; maintaining a senior debt to capitalization ratioof not more than 40%; and maintaining an EBITDA to interest and dividends on preferredstock over the last four quarters in excess of 3.25 to 1.0, increasing to 4.25to 1.0 by March 31, 2005.

 

The new credit facility ranks equally with borrowingsunder our Master Shelf Agreement with The Prudential Insurance Company.

 

***Master Shelf Agreement.  ***Effective January13, 2003, we entered into the Third Amended and Restated Master Shelf Agreementto amend and restate our Master Shelf Agreement with The PrudentialInsurance Company of America.  Amountsoutstanding under the Master Shelf Agreement at March 31, 2003 are as indicatedin the following table (dollars in thousands):

 
| **Issue Date**     |   | **Amount** |    | **Interest  Rate** |   | **Final  Maturity** |              | **Principal  Payments Due**                    |                        |
|--------------------|--------|------------|---------|--------------------|--------|---------------------|-------------------|------------------------------------------------|-----------------------------|
| October  27, 1992  |   | $          | 8,333   |               | 7.99   | %                   | October  27, 2003 |                                           | single  payment at maturity |   |
| December  27, 1993 |   | 25,000     |    | 7.23               | %      | December 27, 2003   |              | single payment at  maturity                    |                        |
| October  27, 1994  |   | 25,000     |    | 9.24               | %      | October 27, 2004    |              | single payment at  maturity                    |                        |
| July  28, 1995     |   | 50,000     |    | 7.61               | %      | July 28, 2007       |              | $ 10,000 on each of July 28, 2003 through 2007 |                        |
|               |   |       |    |               |   |                |              |                                           |                        |
| January  17, 2003  |   | 25,000     |    | 6.36               | %      | January 17, 2008    |              | single payment at  maturity                    |                        |
|               |   | $          | 133,333 |               |   |                |              |                                           |                        |   |

 

Our borrowings under the Master Shelf Agreement aresecured by a pledge of the capital stock of our significant subsidiaries, someof which have also provided a guaranty of payments owed by us under thefacility.  As a result of an amendmentmade on April 24, 2003 to our Master Shelf Agreement, in conjunction with theamendment and restatement of our revolving credit facility, the Master Shelfnow contains additional security, which may be triggered in the event of theissuance of a debt rating downgrade. The Master Shelf requires us to secure loans under the facility with 75%of our oil and gas reserves.  Thisprovision would only be triggered in the event of an issuance of or reductionto a debt rating on the revolving credit facility of Ba3 or lower by Moody’s orthe issuance of or the reduction to a debt rating on the revolving creditfacility of BB- or lower by S&P.

 

Under our Master Shelf Agreement, we are subject to anumber of covenants, including: maintaining a minimum tangible net worth equalto the sum of $300 million plus 50% of consolidated net earnings earned fromJanuary 1, 1999 plus 75% of the net proceeds of any equity offerings afterJanuary 1, 1999; maintaining a total debt to capitalization ratio of not morethan 55% and a senior debt to capitalization ratio of not more than 40%;maintaining a quarterly test of EBITDA to interest for the last four quartersin excess of 3.25 to 1.0, increasing to 4.25 to 1.0 by March 31, 2005; andmaintaining a ratio of senior debt to EBITDA of no greater than 4.0 to 1.0.

 

On January 17, 2003, we borrowed an additional $25.0million under the Master Shelf Agreement. The note bears interest at 6.36% and will be due in a single payment onJanuary 17, 2008.  We have an option toprepay the amount in full, at par on January 18, 2005.  The funds we received from this borrowingwere used in connection with our acquisition of 18 gathering systems in January2003.  In the remaining three quartersof 2003, we will make required principal repayments under the Master ShelfAgreement totaling $43.3 million.  Weintend to fund these repayments with funds available under the revolving creditfacility.

 

***Senior SubordinatedNotes. ***In 1999,we sold $155.0 million of Senior Subordinated Notes in a private placement witha final maturity of 2009 due in a single payment which were subsequentlyexchanged for registered publicly tradable notes under the same terms andconditions.  The Subordinated Notes bearinterest at 10% per annum and were priced at 99.225% to yield 10.125%.  These notes contain covenants, which includelimitations on debt incurrence, restricted payments, liens and sales ofassets.  The Subordinated Notes areunsecured and are guaranteed

 

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on a subordinatedbasis by our material subsidiaries.  Weincurred approximately $5.0 million in offering commissions and expenses, whichwere capitalized and are being amortized over the term of the notes.

 

***CovenantCompliance. ***Wewere in compliance with all covenants in our debt agreements at March 31, 2003.

 

 

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#### ***Upstream Operations***

 

#### **A vital aspect of our long-term business plan is todouble proven reserves and equity production of natural gas from the level atDecember 31, 2001 over a three to five year period.  In order to achieve this goal, we will focus on continueddevelopment of our leasehold positions in the Powder River coal bed methanedevelopment and the Green River Basin. Each of our existing upstream projects are fully integrated with ourmidstream operations. In other words, we provide the gathering, compression,processing, marketing or transportation services for both our own productionand for third-party operators.**

 

***Powder River Basin Coal Bed Methane. ***We continue to developour Powder River Basin coal bed methane reserves and expand the associatedgathering system in northeast Wyoming. The Powder River Basin coal bed methane area is currently one of thelargest on-shore plays for the development of natural gas in the UnitedStates.  Within this area, together withour co-developer, in the first three months of 2003, we were the largest producerof natural gas.  In addition, Western isthe largest gatherer of natural gas and, through our MIGC pipeline, transportsa significant volume of gas out of this basin.

 

At March 31, 2003, we held the drilling rights onapproximately 528,000 net acres in this basin, and as of December 31, 2002, wehad established proven developed and undeveloped reserves totaling 414 Bcfe ona portion of this acreage, 52% of which are proven and developed.   The drilling operations in the Powder RiverBasin through March 31, 2003 have primarily focused on developing reserves inthe Wyodak coal, which is located on the east side of the coal beddevelopment.  We participated in thedrilling of 101 gross wells in the first three months of 2003.  We plan to participate in a total of 845gross wells in 2003, including 441 scheduled to be drilled in the Wyodak coaland 404 scheduled to be drilled in the Big George coal. The average drillingand completion cost for our coal bed methane gas wells is approximately $90,000to $120,000 per well with average reserves per successful well of approximately275 MMcf.  The majority of futuredevelopment will be concentrated on developing the Big George and other coalseams.  Much of the Big George coal seamis deeper and thicker than the Wyodak coal. We expect that as wells are drilled and developed in the Big Georgecoal, the gas reserves and production per well and the average drilling andcompletion cost per well will increase.

 

Our share of production from wells in which we own aninterest averaged approximately 106 MMcfe per day in the first quarter of 2002and increased to an average of approximately 124 MMcfe per day in the firstquarter of 2003.  We currentlyanticipate reaching an average production rate of 132 net MMcfe per day fromthis area in December 2003, assuming that the issuance of permits on federalleases as a result of the EIS, as described below, are not unreasonablydelayed.

 

Industry-wide,production from the Big George coal increased by 293% in 2002 and in February 2003,production rates totaled approximately 82 MMcf per day from eight separatepilots.  We are currently evaluating 11pilot areas and one development area in the Big George.  Through March 31, 2003, we have drilledapproximately 440 gross wells in the Big George coal area.  We have marketable production quantities inthe All Night Creek, Pleasantville and Kingsbury areas.  At April 30, 2003, these areas wereproducing a combined 30.0 gross MMcf per day. At December 31, 2002, we had proven reserves of 49 Bcfe in the BigGeorge coal, primarily associated with the All Night Creek development area.

 

On April 30, 2003, the Bureau of Land Management, orBLM, issued the final Record of Decision, or ROD, in relation to itsEnvironmental Impact Statement, or EIS, regarding future CBM drilling in thePowder River Basin.  We are currently inthe process of reviewing the ROD to determine its impact on our operations inthis area.  More planning will berequired for permitting related to certain plant and animal species, culturalsurveys and noxious weed mitigation.  Weintend to commence filing permit applications for approval by the BLM under theterms of the new EIS, but are unable to predict the rate at which permits willbe granted.  This timing may also beaffected by several lawsuits, which were filed on May 1, 2003 in the U.S.District Court in Billings, Montana challenging the BLM’s decision.  While we believe that these lawsuits areunlikely to be successful, we are unable to predict the outcome of the litigationor the impact, if any, on the timing of our development.

 

Additionally, the Wyoming Department of EnvironmentalQuality, or DEQ, has revised some standards for surface water discharge thathave allowed the issuance of most of the permits that apply to the Cheyenne andBelle Fourche drainage areas. The majority of wells on our acreage producingfrom the Wyodak formation drain into these areas.  The Wyoming and Montana DEQ offices have reached agreement onprocedures for discharging and

 

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monitoring waterinto the Powder River and other drainage areas, in which most of ourundeveloped prospects are located. Additional procedures for obtaining permits under this agreement areaddressed in the EIS referred to above.

 

On April 26, 2002, theInterior Board of Land Appeals, or IBLA, ruled that the BLM did not comply withthe National Environmental Policy Act, or NEPA, prior to issuing three federaloil and gas leases held by an unaffiliated third-party in the Powder RiverBasin.  There has not been a finaldecision regarding the validity of the three leases.  The IBLA has remanded the case to the Wyoming BLM State Directorwithout specifying a remedy.  The StateDirector could, among other things, require additional NEPA analysis to be doneon these three leases. The unaffiliated leaseholder has filed for judicialreview in federal district court in Wyoming. We do not have any interests in these leases nor have we received noticeof any challenge to leases that we hold. We are continuing to monitor the development of the issue. The recentlyconcluded EIS includes a NEPA analysis covering coal bed methane development,which may resolve the defects identified by the IBLA.  

 

Our 2003 capital budget in the Powder River Basin coalbed development includes approximately $55.2 million for drilling costs,production equipment and lease acquisitions, of which approximately $9.2million was spent in the first quarter of 2003.  Depending upon future drilling success, we may need to makeadditional capital expenditures or leasing commitments to continue expansion inthis basin.  In addition, due toregulatory uncertainties, which are beyond our control, we can make noassurance that we will incur this level of capital expenditure.  Our co-developer in this area is alsorequired to make similar capital commitments to continue the pace of thedevelopment as planned.  During 2002,our co-developer in this area publicly disclosed that it had financialdifficulties.  We are currently unableto predict the impact, if any, of our co-developer’s financial situation on thefuture pace of development in the Powder River Basin.  Several disputes have arisen between our co-developer and us.  These disputes are more fully described inPart II — Other Information - Item 1. Legal Proceedings.

 

***Green River Basin.* **Our upstream assets in the Green RiverBasin of southwest Wyoming are located in the Jonah Field and PinedaleAnticline areas.  As of March 31, 2003,we owned approximately 194,000 gross oil and gas leasehold acres, orapproximately 33,000 net acres, in these areas.  During the first quarter of 2003, we participated five grosswells, or one net well, in these areas, at a cost of $1.6 million andexperienced a success rate of 100%.  Ourcapital budget for 2003 in the Jonah Field and Pinedale Anticline areasprovides for expenditures of approximately $17.9 million for drilling costs andproduction equipment.  Due to drillingand regulatory uncertainties, which are beyond our control, there can be noassurance that we will incur this level of capital expenditure.  During the remainder of 2003, we expect toparticipate in the drilling of 60 gross wells, or approximately seven net wellson the Pinedale Anticline.  The expecteddrilling and completion costs per gross well range from approximately $3.5million to $5.0 million, depending on location and depth.  Average well depths in this area range fromapproximately 13,000 feet to 14,200 feet depending on the objective formationand average gross reserves per successful well approximate 6 to 8 Bcfe.  During March 2003, we produced an average of19.5 MMcfe per day, net, from these areas. We had established proven developed and undeveloped reserves totaling161 Bcfe at December 31, 2002.  There canbe no assurance, however, as to the ultimate recovery of these reserves.

 

***ProductionInformation.***  Thefollowing table provides a summary of our net quarterly production volumes:

 
|                        |   | **Three Months Ended March 31,** |   |
|-----------------------------|--------|----------------------------------|--------|
|                        |   | **2003**                         |   | **2002** |   |
| **State/Basin**             |   | **Gas  (MMcf)**                  |   | **Oil  (MBbl)** |   | **Gas  (MMcf)** |   | **Oil  (MBbl)** |   |
|                        |   |                             |   |   |   |   |   |   |   |
| Colorado  - Sand Wash Basin |   | 292                              |   | 1 |   | 228 |   | — |   |
| Texas  (1)                  |   | 8                                |   | 2 |   | 14 |   | 3 |   |
| Wyoming:                    |   |                             |   |   |   |   |   |   |   |
| Powder  River Basin         |   | 11,196                           |   | — |   | 9,579 |   | — |   |
| Green  River Basin          |   | 1,618                            |   | 11 |   | 1,050 |   | 7 |   |
|                        |   |                             |   |   |   |   |   |   |   |
| Total                       |   | 13,114                           |   | 14 |   | 10,871 |   | 10 |   |

 

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(1)                    Represents asmall non-operating working interest in several wells in the Austin Chalk area.

 

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

 

Our midstream operations consist of our gathering,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.  Toachieve this goal, we must continue our efforts to add to natural gasthroughput levels through new well connections and through the expansion oracquisition of gathering or processing systems.  We also seek to increase the efficiency of our operations bymodernization of equipment and the consolidation of existing facilities.

 

Effective February 1, 2003, we acquired 18 gatheringsystems in Wyoming, primarily located in the Green River Basin with smalleroperations in the Powder River and Wind River Basins, for a total of $37.1million.  These assets were acquiredfrom EPFS, and related entities.  Thesesystems are comprised of a total of 550 miles of gathering lines and, in March2003, were gathering a total of 133 MMcf per day.  The three largest systems are located in the Wamsutter area ofthe Greater Green River Basin.   Four ofthese systems are located in the Wind River Basin and provide us with theopportunity to expand our gathering and processing activities into an area inwhich we have not previously operated. Several of the systems are located in the Powder River Basin, do notintegrate directly into our existing systems and will likely be disposed of.

 

***Gas Gathering,Processing and Treating.***

 

At March 31, 2003, we operated a total of 21significant gathering, processing and treating facilities, or plant operations,with approximately 9,797 miles of gathering lines.  These facilities are located in five states and have a combinedthroughput capacity of 2.9 billion cubic feet, Bcf, per day of naturalgas.  Our operations are located in some of the mostactively drilled oil and gas producing basins in the United States.  Five of our processing plants canfurther separate, or fractionate, the mixed NGL stream into ethane, propane,normal butane and natural gasoline to obtain a higher value for the NGLs, andthree of our plants are capable of processing and treating natural gascontaining hydrogen sulfide or other impurities that require removal prior todelivery to market pipelines.   In the first quarter of 2003, we gatheredan average of 1.3 Bcf per day of natural gas, produced natural gas for deliveryto markets of 874 MMcf per day and produced 1.8 MMgal per day of NGLs.  In addition to our integrated upstream andmidstream operations in the Powder River and Green River Basins in Wyoming, our core assetsinclude our plant operations located in west Texas and Oklahoma.  We believe that our core assets have stableproduction rates, provide a significant operating cash flow and continue toprovide us with strategic growth opportunities.

 

#### ***PowderRiver Basin*.**Our midstream operations in the Powder River Basin are fully integratedwith our upstream operations.  In otherwords, we provide the gathering, compression and processing services for bothour own production and for third-party operators.  As of March 31, 2003, our assets in the Powder River Basin innortheast Wyoming were primarily comprised of our coal bed methane gatheringsystem with a capacity of 525 MMcf per day, our 13% equity interest in FortUnion and several small gas processing facilities.

 

We are the constructionmanager and field operator of the Fort Union gathering system and header.  The Fort Union system delivers coal bedmethane gas to a treating facility near Glenrock, Wyoming and accesses interstatepipelines serving gas markets in the Rocky Mountain and Midwest regions of theUnited States.  The gathering pipelinehas a capacity of 635 MMcf per day.  Wehave entered into long-term, firm gathering agreements with Fort Union for 83MMcf per day of capacity at $0.14 per Mcf.

 

Ourcapital budget in the Powder River Basin for midstream activitiesprovides for expenditures of approximately $14.7 million during 2003, of whichapproximately $3.3 million was spent in the first quarter.  We have also entered into a number of operatingleases for compression equipment primarily in the coal bed gathering area.  Depending upon our future drilling success,we may need to make additional capital expenditures or leasing commitments tocontinue expansion in this basin.  Dueto drilling, regulatory, commodity pricing and other uncertainties, which arebeyond our control, there can be no assurance that we will incur this level ofcapital expenditure.

 

***Green River Basin***.  Ourmidstream operations in the Green River Basin of southwest Wyoming are alsofully integrated with our upstream operations in this area.  Our midstream assets in this basin arecomprised of the Granger and Lincoln Road facilities, or collectivelythe Granger complex, our 50% equity interest in Rendezvous and our Red Desertfacility.  These facilities have acombined gathering capacity of 465 MMcf per day and a combined processingcapacity of 327 MMcf per day.  In thethree months ended March 31, 2003, these facilities averaged throughput of 393MMcf per day.

 

Our2003 capital budget for midstream activities in this basin provides forexpenditures of approximately $63.9 million

 

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during 2003 ofwhich $37.3 million was spent in the first quarter.  This capital budget includes approximately $21.2 million forgathering lines and installation of compression to expand the capacity of ourGranger Complex, $5.6 million for additional contributions to Rendezvous forthe expansion of its system and $37.1 million for the acquisition of 18additional gathering systems in January 2003.  Due to drilling, commodity pricing and regulatory uncertainties, whichare beyond our control, there can be no assurance that we will incur this levelof capital expenditure.

 

In 2001, we, together with an unrelated third-party,formed Rendezvous.  Rendezvous gathersgas along the Pinedale Anticline for blending or processing at either ourGranger Complex or at the third-party owned and operated Blacks Fork processingfacility.   Each company owns a 50%interest in Rendezvous, and we serve as field operator of its systems.Rendezvous has a capacity of 275 MMcf per day and at March 31, 2003 wasgathering 234 MMcf per day.   Anexpansion of the system is scheduled to be completed in the fourth quarter of2003.  The expansion would extend thesystem approximately 24 miles further into the Pinedale Anticline at anestimated cost of $11.1 million gross, of which our share is approximately $5.6million.

 

***West Texas******.* **Ourprimary assets in west Texas are the Midkiff/Benedum complex and the Gomeztreating facility.  These facilitiesprocess gas produced by third-parties in the Permian Basin, have a combinedoperational capacity of 565 MMcf per day and processed an average of 280 MMcfper day in the first quarter of 2003. Also in this quarter, these facilities produced an average of 205 MMcfper day of natural gas for delivery to sales markets and produced an average of772 MGal per day of NGLs.  Our capitalbudget in this area provides for expenditures of approximately $6.0 millionduring 2003, of which $500,000 was spent in the first quarter.

 

***Oklahoma******.* **Ourprimary assets in Oklahoma are the Chaney Dell and Westana systems.  These facilities process gas produced bythird-parties in the Anadarko Basin and have a combined operational capacity of175 MMcf per day.  In the three monthsended March 31, 2003, these facilities processed an average of 152 MMcf perday, produced an average of 135 MMcf per day of natural gas for delivery tosales markets and produced 301 MGal per day of NGLs.  Our capital budget in this area provides for expenditures ofapproximately $9.0 million during 2003, of which approximately $1.4 million hasbeen spent in the first quarter.

 

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***PrincipalFacilities.***  Thefollowing tables provide information concerning our principal gathering,processing and treating facilities and transportation assets at March 31,2003.  We also own and operate severalsmaller treating, processing and transportation facilities located in the sameareas as our other facilities.

 
|                            |   |                         |   |                                  |   |                                       |   | **Average  for the Three Months Ended  March 31, 2003** |   |
|---------------------------------|--------|------------------------------|--------|---------------------------------------|--------|--------------------------------------------|--------|---------------------------------------------------------|--------|
| **Facilities  (1)**             |   | **Year  Placed  In Service** |   | **Gas  Gathering  System  Miles (2)** |   | **Gas  Throughput  Capacity  (MMcf/D (3)** |   | **Gas  Throughput  (MMcf/D (4)**                        |   | **Gas  Production  (MMcf/D (5)** |   | **NGL  Production  (MGal/D (5)** |   |
| Texas                           |   |                         |   |                                  |   |                                       |   |                                                    |   |   |   |   |   |
| Gomez  Treating (6)             |   | 1971                         |   | 386                                   |   | 280                                        |   | 84                                                      |   | 76 |   | — |   |
| Midkiff/Benedum                 |   | 1949                         |   | 2,222                                 |   | 165                                        |   | 131                                                     |   | 89 |   | 771 |   |
| Mitchell  Puckett Gathering (6) |   | 1972                         |   | 93                                    |   | 120                                        |   | 64                                                      |   | 40 |   | 1 |   |
| Wyoming                         |   |                         |   |                                  |   |                                       |   |                                                    |   |   |   |   |   |
| Coal  Bed Methane Gathering     |   | 1990                         |   | 1,298                                 |   | 525                                        |   | 414                                                     |   | 220 |   | — |   |
| Desert  Springs Gathering (13)  |   | 1979                         |   | 65                                    |   | 10                                         |   | 4                                                       |   | 4 |   | 2 |   |
| Fort  Union Gas Gathering       |   | 1999                         |   | 106                                   |   | 635                                        |   | 474                                                     |   | 474 |   | — |   |
| Granger  (7)(8)(9)              |   | 1987                         |   | 532                                   |   | 235                                        |   | 237                                                     |   | 153 |   | 407 |   |
| Hilight  Complex (7)            |   | 1969                         |   | 626                                   |   | 124                                        |   | 14                                                      |   | 9 |   | 48 |   |
| Kitty/Amos  Draw (7)            |   | 1969                         |   | 314                                   |   | 17                                         |   | 6                                                       |   | 4 |   | 25 |   |
| Lincoln  Road (9)               |   | 1988                         |   | 149                                   |   | 50                                         |   | 32                                                      |   | — |   | — |   |
| Newcastle  (7)                  |   | 1981                         |   | 146                                   |   | 5                                          |   | 3                                                       |   | 2 |   | 19 |   |
| Red  Desert (7)                 |   | 1979                         |   | 111                                   |   | 42                                         |   | 21                                                      |   | 10 |   | 12 |   |
| Rendezvous  Gas Services        |   | 2001                         |   | —                                |   | 275                                        |   | 224                                                     |   | 224 |   | — |   |
| Reno  Junction (8)              |   | 1991                         |   | —                                |   | —                                     |   | —                                                  |   | — |   | 100 |   |
| Table  Rock Gathering (13)      |   | 1979                         |   | 101                                   |   | 20                                         |   | 11                                                      |   | 11 |   | — |   |
| Wamsutter  Gathering (13)       |   | 1979                         |   | 185                                   |   | 50                                         |   | 26                                                      |   | 26 |   | 10 |   |
| Wind  River Gathering (13)      |   | 1979                         |   | 109                                   |   | 80                                         |   | 36                                                      |   | 36 |   | — |   |
| Oklahoma                        |   |                         |   |                                  |   |                                       |   |                                                    |   |   |   |   |   |
| Chaney  Dell                    |   | 1966                         |   | 2,093                                 |   | 130                                        |   | 87                                                      |   | 84 |   | 296 |   |
| Westana                         |   | 1981                         |   | 1,017                                 |   | 45                                         |   | 63                                                      |   | 51 |   | 5 |   |
| New  Mexico                     |   |                         |   |                                  |   |                                       |   |                                                    |   |   |   |   |   |
| San  Juan River (6)             |   | 1955                         |   | 140                                   |   | 60                                         |   | 30                                                      |   | 24 |   | 49 |   |
| Utah                            |   |                         |   |                                  |   |                                       |   |                                                    |   |   |   |   |   |
| Four  Corners Gathering         |   | 1988                         |   | 104                                   |   | 15                                         |   | 3                                                       |   | 2 |   | 16 |   |
| Total                           |   |                         |   | 9,797                                 |   | 2,883                                      |   | 1,964                                                   |   | 1,539 |   | 1,761 |   |

 
|                              |   |                        |   |                         |   | **Average for the Three Months Ended  March 31, 2003** |   |
|-----------------------------------|--------|-----------------------------|--------|------------------------------|--------|--------------------------------------------------------|--------|
| **Transportation Facilities (1)** |   | **Year Placed  In Service** |   | **Transportation  Miles(2)** |   | **PipelineCapacity  (MMcf/D)(2)**                      |   | **GasThroughput  (MMcf/D)(4)** |   |
| MIGC  (10)(12)                    |   | 1970                        |   | 245                          |   | 130                                                    |   | 179 |   |
| MGTC  (11)                        |   | 1963                        |   | 252                          |   | 18                                                     |   | 14 |   |
| Total                             |   |                        |   | 497                          |   | 148                                                    |   | 193 |   |

 

Footnotes on followingpage.

 

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(1)                   Our interest inall facilities is 100% except for Midkiff/Benedum (73%); Newcastle (50%); FortUnion gathering system (13%) and Rendezvous Gas Services (50%).  We operate all facilities, and all datainclude our interests and the interests of other joint interest owners andproducers of gas volumes dedicated to the facility.  Unless otherwise indicated, all facilities shown in the table aregathering, processing or treating facilities.

(2)                   Gas gatheringsystem miles, transportation miles and pipeline capacity are as of March 31,2003.

(3)                   Gas throughputcapacity is as of March 31, 2003 and represents capacity in accordance withdesign specifications unless other constraints exist, including permitting orfield compression limits.

(4)                   Aggregatewellhead natural gas volumes collected by a gathering system or volumestransported by a pipeline.

(5)                   Volumes of gasand NGLs are allocated to a facility when a well is connected to that facility;volumes exclude NGLs fractionated for third-parties.

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

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

(8)                   NGL productionincludes conversion of third-party feedstock to iso-butane.

(9)                   Lincoln Road isoperated on an intermittent basis to process excess gas from the Grangersystem.

(10)             MIGC is an interstatepipeline located in Wyoming and is regulated by the Federal Energy RegulatoryCommission.

(11)             MGTC is a publicutility located in Wyoming and is regulated by the Wyoming Public ServiceCommission.

(12)             Pipeline capacityrepresents certificated capacity at the Powder River junction only and does notinclude interruptible capacity or capacity at other delivery points.

(13)             These facilities wereacquired on January 31, 2003 with an effective date of February 1, 2003.

 

***Transportation.***

 

Weown and operate MIGC, Inc. an interstate pipeline located in the Powder RiverBasin in Wyoming, and MGTC, Inc. an intrastate pipeline located in northeastWyoming.  MIGC charges a 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.  During the three months ended March 31, 2003, MIGC transported anaverage of 178 MMcf per day.  It isanticipated that MIGC will continue to operate around that level through theremainder of 2003.  MIGC earns fees on amonthly basis from firm capacity contracts under which the shipper pays fortransport capacity whether or not the capacity is used and from interruptiblecontracts where a fee is charged based upon volumes received into the pipeline.  Contracts for firm capacity on MIGC range induration from one month to six years and the fees charged average $0.33 perMcf.

 

The FERC has implementedchanges over the past several years to restrict transactions between regulatedpipelines and affiliated companies.  Inaddition, the FERC has proposed to limit the use of affiliates’ employees inthe operation of regulated entities.  InAugust 2002, the FERC issued a Notice of Proposed Rule Making that, if enacted,would require MIGC to establish its own cash management function, including itsown revolving credit facility, and would limit the ability of MIGC to transferfunds to us.  Further, this proposedrule may require us to modify our existing subsidiary guarantees under our debtagreements.  We can make no assurancesas to the ultimate regulations passed by the FERC or the effects suchregulations may have on the operating costs of MIGC or our financial position.

 

MGTCprovides transportation and gas sales to the Wyoming cities of Gillette,Moorcroft and Wright at rates that are subject to the approval of the WyomingPublic Service Commission.  During thethree months ended March 31, 2003, MGTC transported an average of 14 MMcf perday and sold an average of 1 MMcf per day.

 

***Marketing.***

 

***Gas*.*  ***We market gas produced atour wells and our plants and purchased from third-parties to end-users, localdistribution companies, or LDCs, pipelines and other marketing companiesthroughout the United States and Canada. In addition to our offices in Denver, we have marketing offices inHouston, Texas and Calgary, Alberta. Historically, our gas marketing was an outgrowth of our gas processingactivities and was directed toward selling gas processed at our plants toensure their efficient operation. As the natural gas industry becamederegulated and offered more opportunity, we increased our third-party gasmarketing.  Third-party sales, 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.  For the three months ended March 31, 2003,our total gas sales volumes averaged 1.6 Bcf per day, of which 476 MMcf per daywas produced at our plants or from our producing properties.

 

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One of the primary goalsof our gas marketing operations continues to be the preservation andenhancement of the value received for our equity volumes of natural gas.  This goal is achieved through the use ofhedges on the production of our equity natural gas and through the use of firmtransportation capacity.  For example,during the three months ending March 31, 2003, as a result of limited pipelinecapacity from the Rocky Mountain region to market centers in the mid-continentand west coast areas, natural gas in this region has sold at a substantialdiscount to these other market areas. We had commodity price hedges and firm transportation capacity to themid-continent markets on approximately 100% of our equity production in theRocky Mountain area for this time period. This allowed us to realize an approximate $0.42 per Mcf improvement inprice for natural gas per MMbtu relative to the price that would have beenreceived if these hedges and capacity rights had not existed.  We have similar hedges and transportationpositions for approximately 99% of the estimated equity production of naturalgas in the Rocky Mountain region for the remainder of 2003.

 

We sell gas underagreements with varying terms and conditions in order to match seasonal andother changes in demand. As of March 31, 2003, the average duration of oursales contracts was 17 months.  Themarketing of products purchased from third-parties typically results in lowoperating margins relative to the sales price. Revenues for sales of product are recognized at the time the gas isdelivered to the customer and are sensitive to changes in the market prices ofthe underlying commodities.  We recordrevenue on our physical gas marketing activities on a gross basis versus salesnet of purchases basis.  We believe thatthis presentation is required because we obtain title to all the gas that webuy including third-party purchases, bear the risk of loss and credit exposureon these transactions and it is our intention upon entering these contracts totake physical delivery of the natural gas.  Gains and losses on any accompanying financial transactions are recordednet.  Additionally, for our marketingactivities, we utilize mark-to-market accounting. Under mark-to-marketaccounting, the expected margin to be realized over the term of the transactionis recorded in the month of origination. To the extent that a transaction is not fully hedged or there is anyhedge ineffectiveness, additional gains or losses associated with thetransaction may be reported in future periods. In general, we do not expect to increase our third-party sales volumesin 2003 significantly from levels achieved over the last several years, and infact, due to price volatility and credit concerns in the energy industry, ouroverall sales volumes may decrease.

 

***NGLs*.*  ***We market NGLs, or ethane,propane, iso-butane, normal butane, natural gasoline and condensate, producedat our plants and purchased from third-parties, in the Rocky Mountain,Mid-Continent and Southwestern regions of the United States.  A majority of our production of NGLs movesto the Gulf Coast area, which is the largest NGL market in the UnitedStates.  Through the development ofend-use markets and distribution capabilities, we seek to ensure that productsfrom our plants move on a reliable basis, avoiding curtailment of production.  For the three months ended March 31, 2003,NGL sales averaged 1,655 MGal per day, of which 1,394 MGal per day was producedat our plants.

 

Consumers of NGLs areprimarily the petrochemical industry, the petroleum refining industry and theretail and industrial fuel markets.  Asan example, the petrochemical industry uses ethane, propane, normal butane andnatural gasoline as feedstocks in the production of ethylene, which is used inthe production of various plastics products. Over the last several years, the petrochemical industry has increasedits use of NGLs as a major feedstock and is projected to continue to increasesuch usage.  Further, consumers usepropane for home heating, transportation and agricultural applications.  Price, seasonality and the economy primarilyaffect the demand for NGLs.

 

Our NGL sales tothird-parties decreased by approximately 285 MGal per day in the three monthsended March 31, 2003 compared to the same period in 2002 primarily as a resultof the sale of our Toca facility in September 2002.  As in the case of natural gas, we continually monitor and reviewthe credit exposure to our NGL marketing counterparties.

 

We sell NGLs underagreements with varying terms and conditions in order to match seasonal andother changes in demand. At March 31, 2003, the terms of our sales contractsrange from one month to five years.  Themarketing of products purchased from third-parties typically results in lowoperating margins relative to the sales price. Revenues for sales of NGLs are recognized at the time the NGLs aredelivered to the customer and are sensitive to changes in the market prices ofthe underlying commodities.  We recordrevenue on our physical NGL marketing activities on a gross sales versus salesnet of purchases basis.  We believe thatthis presentation is required because we obtain title to all the NGLs that webuy including third-party purchases, bear the risk of loss and credit exposureon these transactions and it is our intention upon entering these contracts totake physical delivery of the product. Gains and losses on any accompanying financial transactions are recordednet.  Additionally, for our marketingactivities we utilize mark-to-market accounting.  Under mark-to-market accounting, the expected margin to be

 

28

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realized over the term of the transaction is recorded in the month oforigination.  To the extent that a transaction is not fully hedged or there is anyhedge ineffectiveness, additional gains or losses associated with thetransaction may be reported in future periods.

 

***Recent Changes toEnvironmental Regulations.***  Federal regulations regarding spill prevention and containmenthave recently been modified to establish a lower threshold of storage capacityof petroleum and petroleum by-products at a site for which a spill preventionplan is required.  We are evaluating allof our assets for compliance with this regulation and estimate thatapproximately 100 existing sites will need to be modified to meet the newrequirements.  We currently estimate ourcosts for compliance to be approximately $2.0 million.  The new spill prevention plans must be inplace for covered assets by August 2004. All modifications called for in those plans must be in place by February2005.

 

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**ITEM 3.****        QUANTITATIVE AND QUALITATIVEDISCLOSURES ABOUT MARKET RISK**

 

Our commodity price riskmanagement program has two primary objectives. The first goal is to preserve and enhance the value of our equityvolumes of gas and NGLs with regard to the impact of commodity price movementson cash flow, net income and earnings per common share in relation to thoseanticipated by our operating budget. The second goal is to manage price risk related to our gas, crude oiland NGL marketing activities to protect profit margins.  This risk relates to fixed price purchaseand sale commitments, the value of storage inventories and exposure to physicalmarket price volatility.

 

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

 

We use futures, swaps andoptions to reduce price risk and basis risk. Basis is the difference in price between the physical commodity beinghedged and the price of the futures contract used for hedging.  Basis risk is the risk that an adversechange in the futures market will not be completely offset by an equal andopposite 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.

 

We enter into futurestransactions on the New York Mercantile Exchange, or NYMEX, and through OTCswaps and options with various counterparties, consisting primarily offinancial institutions and other natural gas companies.  We conduct our standard credit review of OTCcounterparties and have agreements with many of these parties that containcollateral requirements.  We generallyuse standardized swap agreements that allow for offset of positive and negativeexposures.  OTC exposure ismarked-to-market daily for the credit review process.  Our OTC credit risk exposure is partially limited by our abilityto require a margin deposit from our major counterparties based upon themark-to-market value of their net exposure. We are subject to margin deposit requirements under these sameagreements.  In addition, we are subjectto similar margin deposit requirements for our NYMEX counterparties related toour net exposures. In 2003, the prices for natural gas, crude oil and NGLproducts have increased significantly. For example, the NYMEX contract for March 2003 delivery of natural gasclosed at $9.13 per MMbtu as compared to $2.39 per MMbtu for the NYMEX contractfor March 2002.  Primarily as a resultof our equity hedge positions for natural gas and liquid products, we haveposted margin totaling $12.8 million with various counterparties at April 30,2003.

 

We continually monitorand review the credit exposure to our marketing counterparties.  As prices in 2003 have increased over theprevious year, we have become increasingly concerned with our counterpartycredit exposure.  As a result, we havereduced our sales of third-party natural gas volumes to reduce our creditexposure.  Additionally, beginning in2001, we became increasingly concerned with our credit exposure to ourcustomers, primarily a category of our customers generally known as “energymerchants.”  Energy merchants createliquidity in the marketplace for natural gas transactions and have historicallybeen some of our largest suppliers and customers.  In order to minimize our credit exposures, we have utilizedexisting netting agreements to reduce our net credit exposure, established newnetting agreements with additional customers, terminated several long-termmarketing obligations, negotiated accelerated payment terms with severalcustomers, and reduced the amount of credit which we make available to variouscustomers.  Although netting agreementssimilar to those that we utilize have been upheld by bankruptcy courts in thepast, if any of these customers with whom we have netting agreements were tofile for bankruptcy, we can provide no assurance that our agreements will notbe challenged or as to the outcome of any challenge.

 

We have identified oneMaster Swap Agreement containing ratings triggers.  Under this agreement, either party may be required to postadditional collateral in the event of a decrease in their current rating byStandard & Poor’s or Moody’s Investors Service.  Based on our outstanding positions under this agreement and ourcounterparty’s credit rating at April 30, 2003, we were holding approximately$3.4 million of collateral.

 

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

 

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**RiskPolicy and Control.** We control the extent of risk management and marketing activitiesthrough policies and procedures that involve the senior level ofmanagement.  On a daily basis, ourmarketing activities are audited and monitored by our independent riskoversight department, or IRO.  Thisdepartment reports to the Chief Financial Officer, thereby providing aseparation of duties from the marketing department.  Additionally, the IRO reports monthly to the Risk ManagementCommittee, or RMC.  This committee iscomprised of corporate managers and officers and is responsible for developingthe policies and guidelines that control the management and measurement ofrisk. The RMC is also responsible for setting risk limits, includingvalue-at-risk and dollar stop loss limits. Our board of directors approves the risk limit parameters and riskmanagement policy.

 

**Hedge Positions. **As of April 30, 2003, wehave hedged approximately 51% of our projected equity natural gas volumes andapproximately 77% of our estimated equity production of crude oil, condensate,and NGLs.  These contracts aredesignated and accounted for as cash flow hedges.  As such, gains and losses related to the effective portions ofthe changes in the fair value of the derivatives are recorded in Accumulatedother comprehensive income, a component of Stockholders’ equity.  Any gains or losses on these cash flowhedges are recognized in the Consolidated Statement of Operations throughProduct purchases when the hedged transactions occur.  Gains or losses from the ineffective portions of changes in thefair value of cash flow hedges are recognized currently in earnings throughNon-cash change in the fair value of derivatives.  This ineffectiveness is primarily due to the use of crude oilswaps in hedging the variability in the sales price of butanes.  During the three months ended March 31,2003, we recognized a total of $53,000 of loss from the ineffective portions ofour hedges.  Overall, our hedges areexpected to continue to be “highly effective” under SFAS 133 in thefuture.  

 

To qualify as cash flowhedges, the hedge instruments must be designated as cash flow hedges andchanges in their fair value must correlate with changes in the price of theforecasted transaction being hedged so that our exposure to the risk ofcommodity price changes is reduced.  Tomeet this requirement, we hedge both the price of the commodity and the basisbetween that derivative’s contract delivery location and the cash market locationused for the actual sale of the product. This structure attains a high level of effectiveness, insuring that achange in the price of the forecasted transaction will result in an equal andopposite change in the cash price of the hedged commodity.  We utilize crude oil as a surrogate hedgefor butanes.  This typically results inan effective hedge as crude oil and butane prices historically have moved intandem.

 

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### **OutstandingEquity Hedge Positions and the Associated Basis for 2003**.  The following table details our hedge positions as of April 30,2003.  In order to determine the hedgedprice to the particular operating region, deduct the basis differential fromthe NYMEX price.  The prices for NGLs do not include the cost of the hedges of approximately$698,000.

 
| **Product** |   | **Quantity and NYMEX or Settlement Price**                                                                                        |   | **Hedge of Basis Differential**                                                          |
|-------------|--------|-----------------------------------------------------------------------------------------------------------------------------------|--------|------------------------------------------------------------------------------------------|
| Natural gas |   | 50,000 MMbtu per day  with an average price of $3.94 per MMbtu.                                                                   |   | Mid-Continent - 22,000  MMbtu per day with an average basis price of ($0.16) per MMbtu.  |
|        |   |                                                                                                                              |   |                                                                                     |
|        |   | 20,000 MMbtu per day  with a minimum price of $3.50 per MMbtu and an average maximum price of  $4.43/MMbtu.                       |   | Permian - 5,000 MMbtu  per day with an average basis price of ($0.13) per MMbtu.         |
|        |   |                                                                                                                              |   |                                                                                     |
|        |   |                                                                                                                              |   | Rocky Mountain - 43,000  MMbtu per day with an average basis price of ($0.79) per MMbtu. |
|        |   |                                                                                                                              |   |                                                                                     |
| Crude Oil   |   | 55,000 Barrels of crude  oil per month with an average price of $24.97 per barrel.                                                |   | Not Applicable                                                                           |
|        |   |                                                                                                                              |   |                                                                                     |
| Butanes     |   | 50,000 Barrels of crude  oil per month.  Floor at $24.00 per  barrel.  (Crude oil is used as a  surrogate for butanes). |   | Not Applicable                                                                           |
|        |   |                                                                                                                              |   |                                                                                     |
| Propane     |   | 100,000 Barrels per  month.  Average minimum and maximum  price of $0.37 per gallon and $0.50 per gallon, respectively.      |   | Not Applicable                                                                           |
|        |   |                                                                                                                              |   |                                                                                     |
| Ethane      |   | 81,000 Barrels per  month.  Average minimum and maximum  price of $0.25 per gallon and $0.37 per gallon, respectively.       |   | Not Applicable                                                                           |

 

Account balances relatedto equity and transportation hedging transactions at March 31, 2003 were $8.9million in Current Assets from price risk management activities, $24.9 millionin Current Liabilities from price risk management activities, ($5.9) million inDeferred income taxes payable, net, and a $10.3 million after-tax unrealizedloss in Accumulated other comprehensive income, a component of Shareholders’Equity.  Based on commodity prices as ofMarch 31, 2003, the after-tax loss of $10.3 million will be re-classified fromAccumulated other comprehensive income to Total Revenues during the next ninemonths.

 

***Summary of Derivative Positions.***  A summary of the change in our derivativeposition from December 31, 2002 to March 31, 2003 is as follows (dollars inthousands):

 
| Fair value of contracts  outstanding at December 31, 2002              |   | $       | 63      |   |
|------------------------------------------------------------------------|--------|---------|---------|--------|
| Decrease  in value due to change in price                              |   | (25,188 | )       |
| Increase  in value due to new contracts entered into during the period |   | 11,567  |    |
| Gains  realized during the period from existing and new contracts      |   | 274     |    |
| Changes  in fair value attributable to changes in valuation techniques |   | —  |    |
| Fair  value of contracts outstanding at March 31, 2003                 |   | $       | (13,284 | )      |

 

A summary of ouroutstanding derivative positions at March 31, 2003 is as follows (dollars inthousands):

 
|                              |   | **Fair Value  of Contracts at March 31, 2003** |    |
|-----------------------------------|--------|------------------------------------------------|---------|
| **Source of Fair Value**          |   | **Total Fair  Value**                          |    | **Maturing  In  2003** |   | **Maturing  In  2004-2005** |   | **Maturing  In  2006-2007** |   | **Maturing  Thereafter** |   |
| Exchange  published prices        |   | $                                              | (26,621 | ) | $ | (24,580 | ) | $ | (2,041 | ) | — |   | — |   |
| Other  actively quoted prices (1) |   | 19,685                                         |    | 20,262 |   | (569 | ) | $ | (8 | ) | — |   |
| Other  valuation methods (2)      |   | (6,348                                         | )       | (6,349 | ) | 1 |   | — |   | — |   |
| Total  fair value                 |   | $                                              | (13,284 | ) | $ | (10,667 | ) | $ | (2,609 | ) | $ | (8 | ) | — |   |

 

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

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

 

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***Foreign Currency Derivative Market Risk***.  As a normal part of our business, we enterinto physical gas transactions which are payable in Canadian dollars.  We enter into forward purchases and sales ofCanadian dollars from time to time to fix the cost of our future Canadian dollardenominated natural gas purchase, sale, storage, and transportationobligations.  This is done to protectmarketing margins from adverse changes in the U.S. and Canadian dollar exchangerate between the time the commitment for the payment obligation is made and theactual payment date of such obligation. As of March 31, 2003, the net notional value of such contracts wasapproximately $1.1 million in Canadian dollars, which approximates fair marketvalue.

 

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

 

***Evaluation ofdisclosure controls and procedures.***

 

Under the direction of the Chief Executive Officerand President and the Executive Vice President and Chief Financial Officer, wehave reviewed and evaluated our disclosure controls and procedures and believe,as of the date of management’s evaluation, that our disclosure controls andprocedures are reasonably designed to be effective for the purposes for whichthey are intended.  The review andevaluation was performed within 90 days prior to the filing of this report.

 

***Changes in internalcontrols.***

 

There have not been any significant changes in ourinternal controls or any other factors that could significantly affect thesecontrols subsequent to the date of management’s evaluation, including anycorrective actions with regard to significant deficiencies and materialweaknesses.

 

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**PART II****- OTHER INFORMATION**

 

**ITEM 1.****        LEGAL PROCEEDINGS**

 

***Western Gas Resources, Inc. and Lance Oil & Gas Company,Inc. v. Williams Production RMT Company., (Defendant), Civil Action No.CO2-10-394, District Court, County of Sheridan, Wyoming. *** On October 23, 2002, we filed a complaint fordeclaratory relief and damages related to a dispute arising under a developmentagreement and other agreements between the parties. The dispute centers onDefendant’s acquisition of Barrett by merger consummated on August 2,2001.  We believe we were entitled to apreferential right to purchase certain properties of Barrett located in thePowder River Basin of Wyoming and that our consent was required prior toBarrett’s assignment of its interests in the Agreements to the Defendant.  We also believe that Barrett (now Defendant)should no longer be the operator of these properties as a consequence of themerger transaction.

 

In the fourth quarter of 2002, the Defendant assertedbreach of contract claims against us. The Defendant also claimed damages under its gathering agreement withus.  We believe that the Defendant’s assertionshave no merit.  We have also assertedbreach of contract claims against the Defendant for its operatingpractices.  The parties began mediationof these issues in the first quarter of 2003. At this time, we are unable to predict the outcome of this litigation orthe claims scheduled for mediation.

 

***United States of America and ex rel. Jack J. Grynberg v.Western Gas Resources, Inc., et al., United States District Court, District ofColorado, Civil Action No. 97-D-1427. ***We are a******defendant inlitigation, along with 300 natural gas companies in 74 separate actions, filedby Mr. Grynberg on behalf of the federal government.  The allegations made by Mr. Grynberg are that established gasmeasurement and royalty calculation practices improperly deprived the federalgovernment of appropriate natural gas royalties and violate the False ClaimsAct.  The cases have been consolidatedto the United States District Court for the District of Wyoming.  Discovery is in the initial stages todetermine if this matter qualifies as a qui tam (or class) action.  On October 9, 2002, the court dismissed Mr.Grynberg’s valuation claims, and he has appealed this decision.  We believe that Mr. Grynberg’s claims arebaseless and without merit and intend to vigorously contest the allegations inthis case.  At this time, we are unableto predict the outcome of this matter. There have been no material developments in this lawsuit since thematters were reported in our Annual Report on Form 10-K for the year endedDecember 31, 2002.

 

***Price, et al. v. Gas Pipelines, Western Gas Resources, Inc.,et al., District Court, Stevens County, Kansas, Case No. 99-C-30. ***We are adefendant in litigation, along with numerous other natural gas companies, inwhich Mr. Price is claiming an under measurement of gas and Btu volumesthroughout the country.  We along withother natural gas companies filed a motion to dismiss for failure to state aclaim.  The court denied these motionsto dismiss.   In the first quarter of2003, the court denied plaintiff’s motion for certification as a class.  We believe that Mr. Price’s claims arebaseless and without merit and intends to vigorously contest the allegations inthis case.  At this time, we are unableto predict the outcome of this matter.

 

***Wyoming Department of Revenue.**** *TheWyoming Department of Revenue has conducted an audit of Lance Oil & GasCompany, Inc. for the period from January 1, 1998 through December 31,1999.  On March 24, 2003, the Departmentof Revenue notified us that it had assessed additional severance taxes andincreased taxable value for ad valorem tax purposes.  The additional severance and ad valorem taxes claimed by theDepartment of Revenue amount to $196,000 and $351,000, respectively, togetherwith statutory interest.  We believethat the Wyoming

 

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Department of Revenue claims are without merit and intend to vigorouslycontest their assessments.  On April 23,2003, we filed a Notice of Appeal with the Wyoming State Board of Equalization.

 

***Retirement Plan.***  Our retirement plan for our employeesincludes a fund, which allows them to invest in our common stock.  The fund manager, Fidelity Investments,purchases this stock in open market transactions.  Under SEC rules, the stock purchased by the plan participantsduring a portion of 2001 and 2002 may be required to be registered by us.  To resolve this issue, we intend to file aregistration statement on Form S-3 with the SEC and offer to rescind or paydamages related to certain employee-initiated transactions during that period.  Any stock acquired by us through thisrescission offer will be treated as treasury stock.  While we are unable to estimate the cost or results of therescission offer, we do not expect the costs to have a material adverse effecton our financial position or results of operations.

 

***Other Litigation.**** * We are involved invarious other litigation and administrative proceedings arising in the normalcourse of business.  In the opinion ofour management, any liabilities that may result from these claims will not,individually or in the aggregate, have a material adverse effect on ourfinancial position or results of operations.

 

**ITEM 6****.        EXHIBITSAND REPORTS ON FORM 8-K**

 

(a)                   Exhibits:

 
| **Exhibit  Number** |   | **Description**                                                                                                                                                                                                                                                                                                                                                                                                                                      |
|---------------------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 3.1                 |   | Certificate  of Incorporation of Western Gas Resources, Inc.  (Filed as exhibit 3.1 to Western Gas Resources, Inc.’s  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.  (Filed as exhibit 3.2 to Western  Gas Resources, Inc.’s Registration Statement on Form S-1, Registration No.  33-31604 and incorporated herein by reference).                                                                                                                                                                               |
|                |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 3.3                 |   | Certificate of  Designation of 7.25% Cumulative Senior Perpetual Convertible Preferred Stock  of the Company.  (Filed as exhibit 3.5  to Western Gas Resources, Inc.’s Registration Statement on Form S-1,  Registration No. 33-43077 and incorporated herein by reference).                                                                                                                                                               |
|                |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 3.5                 |   | Amended and Restated  Bylaws of Western Gas Resources, Inc. adopted by the Board of Directors on  April 7, 2003.                                                                                                                                                                                                                                                                                                                                     |
|                |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 10.1                |   | Tenth Amendment, dated  January 3, 2003, to Loan Agreement dated April 29, 1999 by and among Western  Gas Resources, Inc., and Bank of America, N.A., as agent, and the Lenders  (previously filed as Exhibit 10.28 to our 2002 Annual Report on Form 10-K and  incorporated herein by reference).                                                                                                                                                   |
|                |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 10.2                |   | Credit Agreement, dated  as of April 24, 2003, among Western Gas Resources, Inc., as Borrower, Bank of  America, N.A., as Administrative Agent and L/C Issuer, Bank One, NA and Fleet  National Bank, as Co-Syndication Agents, The Royal Bank of Scotland plc and  Wachovia Bank, National Association, as Co-Documentation Agents, and the  Other Lenders Party Thereto.                                                                           |
|                |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 10.3                |   | Intercreditor  Agreement, dated as of April 24, 2003, by and among the banks (as defined  therein), Bank of America, N.A., as Administrative Agent for the banks and  The Prudential Insurance Company of America, Pruco Life Insurance Company,  ING Life Insurance & Annuity Company and Prudential Investment Management,  Inc., consented to agreed by Western Gas Resources, Inc. and its subsidiaries  listed therein.                     |
|                |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 10.4                |   | Third Amended and  Restated Master Shelf Agreement, dated as of December 19, 1991 (effective as  of January 13, 2003), by and among Western Gas Resources, Inc. and The  Prudential Insurance Company of America, Pruco Life Insurance Company,  Prudential Investment Management Company, Inc. and ING Life Insurance &  Annuity Company (filed as Exhibit 10.29 to our 2002 Annual Report on Form  10-K and incorporated herein by reference). |
|                |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 10.5                |   | Letter Amendment No. 1  to Third Amended and Restated Master Shelf Agreement, dated as of April 24,  2003, by and among Western Gas Resources, Inc., The Prudential Insurance  Company of America, Pruco Life Insurance Company, Prudential Investment  Management, Inc. and ING Life Insurance & Annuity Company.                                                                                                                               |
|                |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 99                  |   | Section 906  Certification of the Chief Executive Officer and Chief Financial Officer.                                                                                                                                                                                                                                                                                                                                                          |

 

35

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| (b)    |   | Reports on Form 8-K:                                                                                                                                                                    |
|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                    |
|   |   | During  the quarter ended March 31, 2003, we furnished the following Form 8-K  reports:                                                                                            |
|   |   |                                                                                                                                                                                    |
|   |   | •    Current  Report on Form 8-K furnished on February 21, 2003 (dated February 21, 2003)  announcing financial results for the year ended December 31, 2002.       |
|   |   |                                                                                                                                                                                    |
|   |   | •    Current  Report on Form 8-K furnished on February 21, 2003 (dated February 21, 2003)  detailing operational projections for the year ending December 31, 2003. |

 

36

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SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934,the Registrant has duly caused this report to be signed on its behalf by theundersigned, thereunto duly authorized.

 
|               | WESTERN GAS RESOURCES,  INC. |
|--------------------|------------------------------|
|               | (Registrant)                 |
|               |                         |   |
|               |                         |   |
| Date: May 14, 2003 | By:                          | /s/ PETER A. DEA |   |
|               |                         | Peter A. Dea |
|               |                         | Chief Executive Officer  and President |
|               |                         |   |
|               |                         |   |
| Date: May 14, 2003 | By:                          | /s/WILLIAM J. KRYSIAK |   |
|               |                         | William J. Krysiak |
|               |                         | Executive Vice  President - Chief Financial Officer |
|               |                         | (Principal Financial  and Accounting Officer) |

 

37

----

 

SIGNATURES

 

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

 
|               | WESTERN GAS RESOURCES,  INC. |
|--------------------|------------------------------|
|               | (Registrant)                 |
|               |                         |   |
|               |                         |   |
| Date: May 14, 2003 | By:                          |   |   |
|               |                         | Peter A. Dea |
|               |                         | Chief Executive Officer  and President |
|               |                         |   |
|               |                         |   |
| Date: May 14, 2003 | By:                          |   |   |
|               |                         | William J. Krysiak |
|               |                         | Executive Vice  President - Chief Financial Officer |
|               |                         | (Principal Financial  and Accounting Officer) |

 

38

----

 

**CERTIFICATION**

 
| I,  Peter A. Dea, certify that: |
|---------------------------------|
|                            |
| 1.                              |   | I  have reviewed this quarterly report on Form 10-Q of Western Gas  Resources, Inc.; |
|                            |   |   |
| 2.                              |   | Based  on my knowledge, this quarterly report does not contain any untrue statement  of a material fact or omit to state a material fact necessary to make the  statements made, in light of the circumstances under which such statements  were made, not misleading with respect to the period covered by this quarterly  report; |
|                            |   |   |
| 3.                              |   | Based  on my knowledge, the financial statements, and other financial information  included in this quarterly report, fairly present in all material respects  the financial condition, results of operations and cash flows of the registrant  as of, and for, the periods presented in this quarterly report; |
|                            |   |   |
| 4.                              |   | The  registrant’s other certifying officers and I are responsible for establishing  and maintaining disclosure controls and procedures (as defined in Exchange  Act Rules 13a-14 and 15d-14) for the registrant and we have: |
|                            |   |   |
|                            |   | a)      designed such disclosure controls and  procedures to ensure that material information relating to the registrant,  including its consolidated subsidiaries, is made known to us by others within  those entities, particularly during the period in which this quarterly report  is being prepared; |
|                            |   |   |
|                            |   | b)      evaluated the effectiveness of the  registrant’s disclosure controls and procedures as of a date within  90 days prior to the filing date of this quarterly report (the  “Evaluation Date”); and |
|                            |   |   |
|                            |   | c)      presented  in this quarterly report our conclusions about the effectiveness of the  disclosure controls and procedures based on our evaluation as of the  Evaluation Date; |
|                            |   |   |
| 5.                              |   | The  registrant’s other certifying officers and I have disclosed, based on our  most recent evaluation, to the registrant’s auditors and the audit committee  of registrant’s board of directors (or persons performing the equivalent  function): |
|                            |   |   |
|                            |   | a)        all significant deficiencies in the  design or operation of internal controls which could adversely affect the  registrant’s ability to record, process, summarize and report financial data  and have identified for the registrant’s auditors any material weaknesses in  internal controls; and |
|                            |   |   |
|                            |   | b)        any  fraud, whether or not material, that involves management or other employees  who have a significant role in the registrant’s internal controls; and |
|                            |   |   |
| 6.                              |   | The  registrant’s other certifying officers and I have indicated in this quarterly  report whether or not there were significant changes in internal controls or  in other factors that could significantly affect internal controls subsequent  to the date of our most recent evaluation, including any corrective actions  with regard to significant deficiencies and material weaknesses. |

 

 
| Dated:  May 14, 2003 |   |                                   |
|---------------------------|--------|----------------------------------------|
|                      |   | /s/  Peter A. Dea                      |   |
|                      |   | Peter  A. Dea                          |
|                      |   | Chief  Executive Officer and President |
|                      |   |                                   |

 

39

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**CERTIFICATION**

 
| I,  William J. Krysiak, certify that: |
|---------------------------------------|
|                                  |
| 1.                                    |   | I  have reviewed this quarterly report on Form 10-Q of Western Gas  Resources, Inc.; |
|                                  |   |   |
| 2.                                    |   | Based  on my knowledge, this quarterly report does not contain any untrue statement  of a material fact or omit to state a material fact necessary to make the  statements made, in light of the circumstances under which such statements  were made, not misleading with respect to the period covered by this  quarterly report; |
|                                  |   |   |
| 3.                                    |   | Based  on my knowledge, the financial statements, and other financial information  included in this quarterly report, fairly present in all material respects  the financial condition, results of operations and cash flows of the  registrant as of, and for, the periods presented in this quarterly report; |
|                                  |   |   |
| 4.                                    |   | The  registrant’s other certifying officers and I are responsible for establishing  and maintaining disclosure controls and procedures (as defined in Exchange  Act Rules 13a-14 and 15d-14) for the registrant and we have: |
|                                  |   |   |
|                                  |   | a)        designed such disclosure controls and  procedures to ensure that material information relating to the registrant,  including its consolidated subsidiaries, is made known to us by others within  those entities, particularly during the period in which this quarterly report  is being prepared; |
|                                  |   |   |
|                                  |   | b)        evaluated  the effectiveness of the registrant’s disclosure controls and procedures as  of a date within 90 days prior to the filing date of this quarterly  report (the “Evaluation Date”); and |
|                                  |   |   |
|                                  |   | c)        presented  in this quarterly report our conclusions about the effectiveness of the  disclosure controls and procedures based on our evaluation as of the  Evaluation Date; |
|                                  |   |   |
| 5.                                    |   | The  registrant’s other certifying officers and I have disclosed, based on our  most recent evaluation, to the registrant’s auditors and the audit committee  of registrant’s board of directors (or persons performing the equivalent  function): |
|                                  |   |   |
|                                  |   | a)        all significant deficiencies in the  design or operation of internal controls which could adversely affect the  registrant’s ability to record, process, summarize and report financial data  and have identified for the registrant’s auditors any material weaknesses in  internal controls; and |
|                                  |   |   |
|                                  |   | b)        any  fraud, whether or not material, that involves management or other employees  who have a significant role in the registrant’s internal controls; and |
|                                  |   |   |
| 6.                                    |   | The  registrant’s other certifying officers and I have indicated in this quarterly  report whether or not there were significant changes in internal controls or  in other factors that could significantly affect internal controls subsequent  to the date of our most recent evaluation, including any corrective actions  with regard to significant deficiencies and material weaknesses. |

 

 
| Dated:  May 14, 2003 |
|---------------------------|
|                      | /s/  William J. Krysiak |   |
|                      | William  J. Krysiak |
|                      | Executive  Vice President and Chief Financial Officer |
|                      |   |

 

40

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**INDEXTO EXHIBITS**

 
| **Exhibit  Number** |   | **Description**                                                                                                                                                                                                                                                                                                                                                                                                                                      |
|---------------------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 3.1                 |   | Certificate of  Incorporation of Western Gas Resources, Inc.   (Filed as exhibit 3.1 to Western Gas Resources, Inc.’s 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.  (Filed as exhibit 3.2 to Western  Gas Resources, Inc.’s Registration Statement on Form S-1, Registration No.  33-31604 and incorporated herein by reference).                                                                                                                                                                               |
|                |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 3.3                 |   | Certificate of Designation of 7.25% Cumulative  Senior Perpetual Convertible Preferred Stock of the Company.  (Filed as exhibit 3.5 to Western Gas  Resources, Inc.’s Registration Statement on Form S-1, Registration No.  33-43077 dated November 14, 1991 and incorporated herein by reference).                                                                                                                                        |
|                |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 3.5                 |   | Amended and Restated Bylaws of Western Gas  Resources, Inc. adopted by the Board of Directors on April 7, 2003.                                                                                                                                                                                                                                                                                                                                      |
|                |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 10.1                |   | Tenth Amendment, dated January 3, 2003, to Loan  Agreement dated April 29, 1999 by and among Western Gas Resources, Inc., and  Bank of America, N.A., as agent, and the Lenders (previously filed as Exhibit  10.28 to our 2002 Annual Report on Form 10-K and incorporated herein by  reference).                                                                                                                                                   |
|                |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 10.2                |   | Credit Agreement, dated as of April 24, 2003, among  Western Gas Resources, Inc., as Borrower, Bank of America, N.A., as  Administrative Agent and L/C Issuer, Bank One, NA and Fleet National Bank, as  Co-Syndication Agents, The Royal Bank of Scotland plc and Wachovia Bank,  National Association, as Co-Documentation Agents, and the Other Lenders Party  Thereto.                                                                           |
|                |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 10.3                |   | Intercreditor Agreement, dated as of April 24, 2003,  by and among the banks (as defined therein), Bank of America, N.A., as  Administrative Agent for the banks and The Prudential Insurance Company of  America, Pruco Life Insurance Company, ING Life Insurance & Annuity  Company and Prudential Investment Management, Inc., consented to agreed by  Western Gas Resources, Inc. and its subsidiaries listed therein.                      |
|                |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 10.4                |   | Third Amended and Restated Master Shelf Agreement,  dated as of December 19, 1991 (effective as of January 13, 2003), by and  among Western Gas Resources, Inc. and The Prudential Insurance Company of  America, Pruco Life Insurance Company, Prudential Investment Management  Company, Inc. and ING Life Insurance & Annuity Company (filed as Exhibit  10.29 to our 2002 Annual Report on Form 10-K and incorporated herein by  reference). |
|                |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 10.5                |   | Letter Amendment No. 1 to Third Amended and Restated  Master Shelf Agreement, dated as of April 24, 2003, by and among Western Gas  Resources, Inc., The Prudential Insurance Company of America, Pruco Life  Insurance Company, Prudential Investment Management, Inc. and ING Life  Insurance & Annuity Company.                                                                                                                               |
|                |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 99                  |   | Section 906  Certification of the Chief Executive Officer and Chief Financial Officer.                                                                                                                                                                                                                                                                                                                                                          |

 

41

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