**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 JUNE 30,  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           ** |
|                                                                                                                                                                      |
| **Commission file number 1-10389**                                                                                                                                        |

** **

**WESTERN GAS RESOURCES, INC.**

(Exact name of registrant as specified in its charter)

 

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

 

Indicate by check mark whether theregistrant: (1) has filed all reports required to be filed by Section 13 or15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (orfor such shorter period that the registrant was required to file such reports),and (2) has been subject to such filing requirements for the past 90 days. Yes ý  No o

 

Indicate by check mark whether the registrantis an accelerated filer (as defined in Rule 12b-2 under the Exchange Act). Yes ý  No o

 

On August 1, 2003, there were 33,179,544shares of the registrant’s common stock outstanding.

 

 

----

 

**WesternGas Resources, Inc.**

**Form10-Q**

**Table of Contents**

 
| PART I - Financial Information |
|--------------------------------|
|                           |   |   |
|                           | Item 1. | Financial Statements |
|                           |   |   |
|                           |   | Consolidated Balance Sheet - June 30, 2003 and December 31, 2002 |
|                           |   |   |
|                           |   | Consolidated Statement of Cash Flows - Six  Months Ended  June 30, 2003 and 2002 |
|                           |   |   |
|                           |   | Consolidated Statement of Operations -  Three and Six Months Ended  June 30, 2003 and 2002 |
|                           |   |   |
|                           |   | Consolidated Statement of Changes in  Stockholders’ Equity - Six Months Ended  June 30, 2003 |
|                           |   |   |
|                           |   | Condensed Notes to Consolidated Financial  Statements |
|                           |   |   |
|                           | Item 2. | Management’s Discussion and Analysis of  Financial Condition and Results of Operations |
|                           |   |   |
|                           | Item 3. | Quantitative and Qualitative Disclosures  about Market Risk |
|                           |   |   |
|                           | Item 4. | Controls and Procedures |
|                           |   |   |
| PART II - Other Information    |
|                           |   |   |
|                           | Item 1. | Legal Proceedings |
|                           |   |   |
|                           | Item 4. | Submission of Matters to a Vote of Security  Holders |
|                           |   |   |
|                           | Item 6. | Exhibits and Reports on Form 8-K |
|                           |   |   |
| Signatures                     |

 

2

----

 

**PARTI - FINANCIAL INFORMATION**

** **

**ITEM1.     FINANCIAL STATEMENTS**

WESTERN GASRESOURCES, INC.

CONSOLIDATED BALANCE SHEET

(Dollars in thousands, except share data)

 
|                                                                                                                                                                             |   | **June 30,  2003** |      | **December  31,  2002** |   |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|--------------------|-----------|-------------------------|--------|
|                                                                                                                                                                             |   | **(unaudited)**    |      |                    |   |
| **ASSETS**                                                                                                                                                                       |   |               |      |                    |   |
|                                                                                                                                                                             |   |               |      |                    |   |
| Current assets:                                                                                                                                                                  |   |               |      |                    |   |
| Cash and cash equivalents                                                                                                                                                        |   | $                  | 40,231    |                    | $      | 7,312 |   |
| Trade accounts receivable, net                                                                                                                                                   |   | 283,772            |      | 253,587                 |   |
| Inventory                                                                                                                                                                        |   | 59,935             |      | 43,482                  |   |
| Assets held for sale                                                                                                                                                             |   | 1,617              |      | 3,250                   |   |
| Assets from price risk management  activities                                                                                                                                    |   | 17,209             |      | 34,873                  |   |
| Other                                                                                                                                                                            |   | 10,284             |      | 27,744                  |   |
| Total current assets                                                                                                                                                             |   | 413,048            |      | 370,248                 |   |
|                                                                                                                                                                             |   |               |      |                    |   |
| Property and equipment:                                                                                                                                                          |   |               |      |                    |   |
| Gas gathering, processing, storage and  transportation                                                                                                                           |   | 993,663            |      | 942,147                 |   |
| Oil and gas properties and equipment  (successful efforts method)                                                                                                                |   | 298,144            |      | 252,747                 |   |
| Construction in progress                                                                                                                                                         |   | 90,224             |      | 104,033                 |   |
|                                                                                                                                                                             |   | 1,382,031          |      | 1,298,927               |   |
| Less:   Accumulated depreciation, depletion and amortization                                                                                                                |   | (464,560           | )         | (432,281                | )      |
|                                                                                                                                                                             |   |               |      |                    |   |
| Total property and equipment, net                                                                                                                                                |   | 917,471            |      | 866,646                 |   |
|                                                                                                                                                                             |   |               |      |                    |   |
| Other assets:                                                                                                                                                                    |   |               |      |                    |   |
| Gas purchase contracts (net of accumulated  amortization of $38,079 and $ 37,232, respectively)                                                                                  |   | 30,076             |      | 30,924                  |   |
| Assets from price risk management  activities                                                                                                                                    |   | 2,677              |      | 406                     |   |
| Other                                                                                                                                                                            |   | 34,906             |      | 33,920                  |   |
|                                                                                                                                                                             |   |               |      |                    |   |
| Total other assets                                                                                                                                                               |   | 67,659             |      | 65,250                  |   |
|                                                                                                                                                                             |   |               |      |                    |   |
| TOTAL  ASSETS                                                                                                                                                                    |   | $                  | 1,398,178 |                    | $      | 1,302,144 |   |
|                                                                                                                                                                             |   |               |      |                    |   |
| **LIABILITIES AND STOCKHOLDERS’ EQUITY**                                                                                                                                    |   |               |      |                    |   |
| Current liabilities:                                                                                                                                                             |   |               |      |                    |   |
| Accounts payable                                                                                                                                                                 |   | $                  | 305,798   |                    | $      | 242,987 |   |
| Accrued expenses                                                                                                                                                                 |   | 43,021             |      | 51,509                  |   |
| Liabilities from price risk management  activities                                                                                                                               |   | 29,530             |      | 34,811                  |   |
| Dividends payable                                                                                                                                                                |   | 3,469              |      | 3,464                   |   |
| Total current liabilities                                                                                                                                                        |   | 381,818            |      | 332,771                 |   |
|                                                                                                                                                                             |   |               |      |                    |   |
| Long - term debt                                                                                                                                                                 |   | 333,333            |      | 359,933                 |   |
| Liabilities from price risk management  activities                                                                                                                               |   | 1,624              |      | 406                     |   |
| Other long-term liabilities                                                                                                                                                      |   | 21,011             |      | 1,713                   |   |
| Deferred income taxes payable, net                                                                                                                                               |   | 143,095            |      | 124,253                 |   |
|                                                                                                                                                                             |   |               |      |                    |   |
| Total liabilities                                                                                                                                                                |   | 880,881            |      | 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; 33,176,144 and 33,077,611 shares issued, respectively                                                              |   | 3,339              |      | 3,329                   |   |
| Treasury stock, at cost; 25,016 common  shares in treasury                                                                                                                       |   | (788               | )         | (788                    | )      |
| Additional paid-in capital                                                                                                                                                       |   | 383,334            |      | 381,066                 |   |
| Retained earnings                                                                                                                                                                |   | 139,629            |      | 102,292                 |   |
| Accumulated other comprehensive income                                                                                                                                           |   | (8,493             | )         | (2,812                  | )      |
| Notes receivable from key employees secured  by common stock                                                                                                                     |   | —             |      | (295                    | )      |
|                                                                                                                                                                             |   |               |      |                    |   |
| Total stockholders’ equity                                                                                                                                                  |   | 517,297            |      | 483,068                 |   |
|                                                                                                                                                                             |   |               |      |                    |   |
| TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY                                                                                                                                  |   | $                  | 1,398,178 |                    | $      | 1,302,144 |   |

 

The accompanying notes are an integral partof the consolidated financial statements.

 

3

----

 

WESTERN GAS RESOURCES, INC.

CONSOLIDATEDSTATEMENT OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

 
|                                                                                    |   | **Six Months  Ended  June 30,** |    |
|-----------------------------------------------------------------------------------------|--------|---------------------------------|---------|
|                                                                                    |   | **2003**                        |    | **2002** |   |
| Reconciliation of net income to net cash  provided by operating activities:             |   |                            |    |   |   |
| Net income                                                                              |   | $                               | 44,275  |   | $ | 21,766 |   |
| Add income items that do not affect cash:                                               |   |                            |    |   |   |
| Depreciation, depletion and amortization                                                |   | 35,828                          |    | 35,189 |   |
| Loss on the sale of property and equipment                                              |   | 86                              |    | 82 |   |
| Cumulative effect of change in accounting  principle                                    |   | 6,724                           |    | — |   |
| Deferred  income taxes                                                                  |   | 26,989                          |    | 7,855 |   |
| Non-cash  change in fair value of derivatives                                           |   | 480                             |    | 3,129 |   |
| Other non-cash items, net                                                               |   | 1,015                           |    | 1,589 |   |
|                                                                                    |   |                            |    |   |   |
| Adjustments to working capital to arrive at  net cash provided by operating activities: |   |                            |    |   |   |
| (Increase) in trade accounts receivable                                                 |   | (29,987                         | )       | (6,812 | ) |
| (Increase) decrease in product inventory                                                |   | (16,410                         | )       | 13,331 |   |
| (Increase) decrease in other current assets                                             |   | 18,958                          |    | (473 | ) |
| (Increase) decrease in other assets and  liabilities, net                               |   | (298                            | )       | 425 |   |
| Increase (decrease) in accounts payable                                                 |   | 62,811                          |    | (20,899 | ) |
| Increase (decrease) in accrued expenses                                                 |   | (8,821                          | )       | 12,733 |   |
|                                                                                    |   |                            |    |   |   |
| Net cash provided by operating activities                                               |   | 141,650                         |    | 67,915 |   |
|                                                                                    |   |                            |    |   |   |
| Cash flows from investing activities:                                                   |   |                            |    |   |   |
|                                                                                    |   |                            |    |   |   |
| Purchases of property and equipment                                                     |   | (79,551                         | )  | (57,855 | ) |
| Proceeds from the dispositions of property  and equipment                               |   | 3,564                           |    | 465 |   |
| Contributions to equity investees                                                       |   | —                          |    | (6,583 | ) |
|                                                                                    |   |                            |    |   |   |
| Net cash used in investing activities                                                   |   | (75,987                         | )       | (63,973 | ) |
|                                                                                    |   |                            |    |   |   |
| Cash flows from financing activities:                                                   |   |                            |    |   |   |
|                                                                                    |   |                            |    |   |   |
| Net proceeds from exercise of common stock  options                                     |   | 2,618                           |    | 6,514 |   |
| Debt issue costs paid                                                                   |   | (1,829                          | )       | (114 | ) |
| Borrowings on long-term debt                                                            |   | 25,000                          |    | — |   |
| Payments on revolving credit facility                                                   |   | (625,500                        | )       | (522,100 | ) |
| Borrowings under revolving credit facility                                              |   | 573,900                         |    | 537,000 |   |
| Dividends  paid                                                                         |   | (6,933                          | )       | (7,546 | ) |
|                                                                                    |   |                            |    |   |   |
| Net cash provided by (used in) financing  activities                                    |   | (32,744                         | )       | 13,754 |   |
|                                                                                    |   |                            |    |   |   |
| Net  increase in cash and cash equivalents                                              |   | 32,919                          |    | 17,696 |   |
|                                                                                    |   |                            |    |   |   |
| Cash  and cash equivalents at beginning of period                                       |   | 7,312                           |    | 10,032 |   |
|                                                                                    |   |                            |    |   |   |
| Cash  and cash equivalents at end of period                                             |   | $                               | 40,231  |   | $ | 27,728 |   |

 

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

 

4

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WESTERN GASRESOURCES, INC.

CONSOLIDATED STATEMENT OF OPERATIONS 

(Unaudited)

(Dollars in thousands, except share and pershare amounts)

 
|                                                                                               |   | **Three  Months Ended  June 30,** |    | **Six Months  Ended  June 30,** |   |
|----------------------------------------------------------------------------------------------------|--------|-----------------------------------|---------|---------------------------------|--------|
|                                                                                               |   | **2003**                          |    | **2002**                        |   | **2003** |   | **2002** |   |
| Revenues:                                                                                          |   |                              |    |                            |   |   |   |   |   |
| Sale of gas                                                                                        |   | $                                 | 554,090 |                            | $      | 510,198 |   | $ | 1,333,829 |   | $ | 1,055,787 |   |
| Sale of natural gas liquids                                                                        |   | 80,510                            |    | 79,866                          |   | 172,559 |   | 144,674 |   |
| Gathering, processing and transportation  revenue                                                  |   | 21,458                            |    | 15,028                          |   | 41,235 |   | 30,459 |   |
| Non-cash change in fair value of  derivatives                                                      |   | 3,683                             |    | 7,866                           |   | (480 | ) | (3,129 | ) |
| Other                                                                                              |   | 750                               |    | 1,170                           |   | 1,454 |   | 2,253 |   |
| Total revenues                                                                                     |   | 660,491                           |    | 614,128                         |   | 1,548,597 |   | 1,230,044 |   |
|                                                                                               |   |                              |    |                            |   |   |   |   |   |
| Costs and expenses:                                                                                |   |                              |    |                            |   |   |   |   |   |
| Product purchases                                                                                  |   | 559,836                           |    | 528,289                         |   | 1,331,438 |   | 1,072,895 |   |
| Plant and transportation operating expense                                                         |   | 22,612                            |    | 19,790                          |   | 44,534 |   | 38,661 |   |
| Oil and gas exploration and production  expense                                                    |   | 13,290                            |    | 9,142                           |   | 25,801 |   | 16,531 |   |
| Depreciation, depletion and amortization                                                           |   | 17,685                            |    | 17,243                          |   | 35,828 |   | 35,189 |   |
| (Gain) loss on sale of assets                                                                      |   | (195                              | )       | 73                              |   | 86 |   | 82 |   |
| Selling and administrative expense                                                                 |   | 9,923                             |    | 11,887                          |   | 20,515 |   | 20,578 |   |
| Earnings from equity investments                                                                   |   | (1,867                            | )       | (802                            | )      | (3,429 | ) | (1,652 | ) |
| Interest expense                                                                                   |   | 6,429                             |    | 6,770                           |   | 13,243 |   | 13,430 |   |
| Total costs and expenses                                                                           |   | 627,713                           |    | 592,392                         |   | 1,468,016 |   | 1,195,714 |   |
|                                                                                               |   |                              |    |                            |   |   |   |   |   |
| Income before income taxes                                                                         |   | 32,778                            |    | 21,736                          |   | 80,581 |   | 34,330 |   |
| Provision for income taxes:                                                                        |   |                              |    |                            |   |   |   |   |   |
| Current                                                                                            |   | 2,072                             |    | 3,951                           |   | 2,593 |   | 4,709 |   |
| Deferred                                                                                           |   | 9,806                             |    | 4,019                           |   | 26,989 |   | 7,855 |   |
| Total provision for income taxes                                                                   |   | 11,878                            |    | 7,970                           |   | 29,582 |   | 12,564 |   |
|                                                                                               |   |                              |    |                            |   |   |   |   |   |
| Income before cumulative effect of change  in accounting principle                                 |   | 20,900                            |    | 13,766                          |   | 50,999 |   | 21,766 |   |
|                                                                                               |   |                              |    |                            |   |   |   |   |   |
| Cumulative effect of change in accounting  principle, net of tax benefit of $3,967                 |   | —                            |    | —                          |   | (6,724 | ) | — |   |
|                                                                                               |   |                              |    |                            |   |   |   |   |   |
| Net income                                                                                         |   | 20,900                            |    | 13,766                          |   | 44,275 |   | 21,766 |   |
|                                                                                               |   |                              |    |                            |   |   |   |   |   |
| Preferred stock requirements                                                                       |   | (1,811                            | )       | (2,130                          | )      | (3,623 | ) | (4,260 | ) |
|                                                                                               |   |                              |    |                            |   |   |   |   |   |
| Income attributable to common stock                                                                |   | $                                 | 19,089  |                            | $      | 11,636 |   | $ | 40,652 |   | $ | 17,506 |   |
|                                                                                               |   |                              |    |                            |   |   |   |   |   |
| Net income per share of common stock before  cumulative effect of a change in accounting principle |   | $                                 | .58     |                            | $      | .35 |   | $ | 1.43 |   | $ | .53 |   |
|                                                                                               |   |                              |    |                            |   |   |   |   |   |
| Cumulative effect of a change in accounting  principle                                             |   | $                                 | —  |                            | $      | — |   | $ | .20 |   | $ | — |   |
|                                                                                               |   |                              |    |                            |   |   |   |   |   |
| Earnings per share of common stock                                                                 |   | $                                 | .58     |                            | $      | .35 |   | $ | 1.23 |   | $ | .53 |   |
|                                                                                               |   |                              |    |                            |   |   |   |   |   |
| Weighted average shares of common stock  outstanding                                               |   | 33,147,943                        |    | 32,994,543                      |   | 33,117,812 |   | 32,877,312 |   |
|                                                                                               |   |                              |    |                            |   |   |   |   |   |
| Income  attributable to common stock – assuming dilution                                      |   | $                                 | 20,900  |                            | $      | 11,636 |   | $ | 44,275 |   | $ | 17,506 |   |
|                                                                                               |   |                              |    |                            |   |   |   |   |   |
| Earnings per share of common stock – assuming dilution                                        |   | $                                 | .56     |                            | $      | .34 |   | $ | 1.19 |   | $ | .52 |   |
|                                                                                               |   |                              |    |                            |   |   |   |   |   |
| Weighted average shares of common stock  outstanding - assuming dilution                           |   | 37,263,359                        |    | 33,779,869                      |   | 37,208,441 |   | 33,621,877 |   |

 

The accompanying notes are an integral partof the consolidated financial statements.

 

5

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WESTERN GAS RESOURCES, INC.

CONSOLIDATEDSTATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

(Dollars in thousands, 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, six months ended June 30, 2003                          |   | —                                                |   | —                       |   | —                                    |   | —                                                |   | —            |   | —              |   | —                           |   | 44,275                 |   | —                                                    |   | —                                     |    | 44,275                                   |   |
| Translation adjustments                                             |   | —                                                |   | —                       |   | —                                    |   | —                                                |   | —            |   | —              |   | —                           |   | —                 |   | 687                                                       |   | —                                     |    | 687                                      |   |
| Reclassification adjustment for settled contracts                   |   | —                                                |   | —                       |   | —                                    |   | —                                                |   | —            |   | —              |   | —                           |   | —                 |   | 2,142                                                     |   | —                                     |    | 2,142                                    |   |
| Changes in fair value of outstanding hedging positions              |   | —                                                |   | —                       |   | —                                    |   | —                                                |   | —            |   | —              |   | —                           |   | —                 |   | (9,375                                                    | )      | —                                     |    | (9,375                                   | )      |
| Reduction due to estimated ineffectiveness                          |   | —                                                |   | —                       |   | —                                    |   | —                                                |   | —            |   | —              |   | —                           |   | —                 |   | —                                                    |   | —                                     |    | —                                   |   |
| Fair value of new hedge positions                                   |   | —                                                |   | —                       |   | —                                    |   | —                                                |   | —            |   | —              |   | —                           |   | —                 |   | 865                                                       |   | —                                     |    | 865                                      |   |
| Change in accumulated derivative comprehensive income               |   | —                                                |   | —                       |   | —                                    |   | —                                                |   | —            |   | —              |   | —                           |   | —                 |   | (6,368                                                    | )      | —                                     |    | (6,368                                   | )      |
|                                                                |   |                                                  |   |                         |   |                                      |   |                                                  |   |              |   |                |   |                             |   |                   |   |                                                      |   |                                       |    |                                     |   |
| Total comprehensive income, net of tax                              |   |                                                  |   |                         |   |                                      |   |                                                  |   |              |   |                |   |                             |   |                   |   |                                                      |   |                                       |    | 38,594                                   |   |
| Stock options exercised                                             |   | —                                                |   | 98,533                       |   | —                                    |   | —                                                |   | 10                |   | —              |   | 1,740                            |   | —                 |   | —                                                    |   | —                                     |    | 1,750                                    |   |
| Effect of re-priced stock options                                   |   | —                                                |   | —                       |   | —                                    |   | —                                                |   | —            |   | —              |   | 528                              |   | —                 |   | —                                                    |   | —                                     |    | 528                                      |   |
| Loans forgiven                                                      |   | —                                                |   | —                       |   | —                                    |   | —                                                |   | —            |   | —              |   | —                           |   | —                 |   | —                                                    |   | 295                                        |    | 295                                      |   |
| Dividends declared on common stock ($.10 per common share)          |   | —                                                |   | —                       |   | —                                    |   | —                                                |   | —            |   | —              |   | —                           |   | (3,315                 | )      | —                                                    |   | —                                     |    | (3,315                                   | )      |
| Dividends declared on $2.625 cumulative convertible preferred stock |   | —                                                |   | —                       |   | —                                    |   | —                                                |   | —            |   | —              |   | —                           |   | (3,623                 | )      | —                                                    |   | —                                     |    | (3,623                                   | )      |
|                                                                |   |                                                  |   |                         |   |                                      |   |                                                  |   |              |   |                |   |                             |   |                   |   |                                                      |   |                                       |    |                                     |   |
| Balance at June 30, 2003                                            |   | 2,760,000                                             |   | 33,176,144                   |   | 25,016                                    |   | $                                                     | 276    |              | $      | 3,339               |   | $                                | (788   | )                      | $      | 383,334                                                   |   | $                                          | 139,629 |                                     | $      | (8,493 | ) | $ | — |   | $ | 517,297 |   |

 

The accompanying notes are an integral partof the consolidated financial statements.

 

6

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WESTERN GAS RESOURCES, INC.

CONDENSEDNOTES TO CONSOLIDATED FINANCIAL STATEMENTS 

(Unaudited)

 

***GENERAL***

 

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

 

The interim consolidated financial statementspresented herein should be read in conjunction with the Consolidated FinancialStatements and Notes thereto included in our Annual Report on Form 10-K for theyear ended December 31, 2002.  Theinterim consolidated financial statements as of June 30, 2003 and for the threeand six month periods ended June 30, 2003 and 2002 included herein areunaudited but reflect, in the opinion of management, all adjustments (which includeonly normal recurring adjustments) necessary to fairly present the results forsuch periods.  The results of operationsfor the three and six months ended June 30, 2003 are not necessarily indicativeof the results of operations expected for the year ended December 31, 2003.

 

Prior period amounts in the interimconsolidated financial statements and notes have been reclassified asappropriate to conform to the presentation used in 2003.

 

***EARNINGS PER SHAREOF COMMON STOCK***

 

Earnings per share of common stock arecomputed by dividing income attributable to common stock by the weightedaverage shares of common stock outstanding. In addition, earnings per share of common stock - assuming dilution iscomputed by dividing income attributable to common stock by the weightedaverage shares of common stock outstanding as adjusted for potential commonshares.  Income attributable to commonstock is income less preferred stock dividends.  We declared preferred stock dividends of $1.8 million and $2.1million for the three months ended June 30, 2003 and 2002, respectively, and$3.6 million and $4.3 million, respectively, for the six month period endedJune 30, 2003 and 2002. Common stock options and our $2.625 CumulativeConvertible Preferred Stock are potential common shares.   The following is a reconciliation of the weighted averageshares of common stock outstanding to the weighted average common sharesoutstanding – assuming dilution.

** **
|                                                                     |   | **Quarter Ended June 30,** |   | **Six Months Ended June 30,** |   |
|--------------------------------------------------------------------------|--------|----------------------------|--------|-------------------------------|--------|
|                                                                     |   | **2003**                   |   | **2002**                      |   | **2003** |   | **2002** |   |
| Weighted average shares of common stock  outstanding                     |   | 33,147,943                 |   | 32,994,543                    |   | 33,117,812 |   | 32,877,312 |   |
| Potential common shares from:                                            |   |                       |   |                          |   |   |   |   |   |
| Common stock options                                                     |   | 643,718                    |   | 785,326                       |   | 618,931 |   | 744,565 |   |
| $2.625 Cumulative Convertible Preferred Stock                            |   | 3,471,698                  |   | —                        |   | 3,471,698 |   | — |   |
| Weighted average shares of common stock outstanding - assuming  dilution |   | 37,263,359                 |   | 33,779,869                    |   | 37,208,441 |   | 33,621,877 |   |

 

The numeratorsand the denominators for these periods were adjusted to reflect these potentialshares and any related preferred dividends in calculating fully dilutedearnings per share.

 

***ACCUMULATED OTHER COMPREHENSIVE INCOME***

 

Included inAccumulated other comprehensive income at June 30, 2003 were unrealized lossesof $11.8 million from the fair value of derivatives designated as cash flowhedges and unrealized gains of $3.3 million of cumulative foreign currencytranslation adjustments.

 

Included inAccumulated other comprehensive income at June 30, 2002 were unrealized gainsof $5.2 million from the fair value of derivatives designated as cash flowhedges and $2.5 million of cumulative foreign currency translation adjustments.

 

***CUMULATIVE EFFECT OFA CHANGE IN ACCOUNTING PRINCIPLE***

 

In June 2001,the FASB issued SFAS No. 143 “Accounting for Asset RetirementObligations.”  SFAS No. 143 was effective for fiscal yearsbeginning after June 15, 2002.  SFAS No.143 establishes accounting standards for recognition and measurement of aliability for an asset retirement obligation and the associated assetretirement cost.  We adopted SFAS No.

 

7

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143 on January 1, 2003 and recorded a $11.5 million increase to Propertyand Equipment, a $4.4 million increase to Accumulated depreciation,depletion and amortization, a $17.8 million increase to Other long-termliabilities and a $6.7 million non-cash, after-tax loss from the Cumulative effect of a change inaccounting principle.

 

The followingis a reconciliation of the asset retirement obligation for the six months ended June 30, 2003(dollars in thousands):

 
| Asset retirement obligation as of  January 1, 2003 |   | $     | 17,801 |   |
|----------------------------------------------------|--------|-------|--------|--------|
| Liability accrued upon capital  expenditures       |   | 1,258 |   |
| Liability settled                                  |   | (42   | )      |
| Accretion of discount expense                      |   | 566   |   |
| Asset retirement obligation as of June  30, 2003   |   | $     | 19,583 |   |

 

Exclusive of assets disposed of during 2002,if we had adopted SFAS No. 143 as of January 1, 2002, we estimate that theasset retirement obligation at that date would have been $15.7 million, basedon the same assumptions used in our calculation of the obligation at January 1,2003.  The estimated 2002 pro formaeffect of a hypothetical January 1, 2002 adoption of SFAS No. 143 on net incomeand earnings per share, for annual and interim periods, is not material.

 

Inconnection with the adoption of SFAS No. 143, we completed a review of ouroperating assets and reevaluated the operating life and salvage values of theassociated equipment.  As a result of this evaluation, we extended the useful life of many ofour operating assets and adjusted the estimated salvage value of our operatingequipment.  These adjustments resultedin an approximate $3.3 million and $5.8 million, respectively, or $0.06 and$0.10 per share of common stock - assuming dilution, respectively, decrease in depreciation, depletion and amortization in the three and six months ended June 30, 2003, from the expensecalculated using the previous useful lives. The adjustments to the salvage value and depreciable lives of our assetsare treated as a revision of an estimate and are accounted for on a prospectivebasis.

** **

***OTHER INFORMATION***

*** ***

***Acquisition ofGathering Systems.***  Effective February 1, 2003, we acquired 18 gathering systems inWyoming, primarily located in the Green River Basin with smaller operations inthe Powder River and Wind River Basins, for a total of $37.1 million.  Several of the systems located in the PowderRiver Basin do not integrate directly into our existing systems, andaccordingly we are negotiating for the sale of these systems.  These systems are classified as Assets heldfor sale on the Consolidated Balance Sheet at June 30, 2003.  During the three and six months ended June30, 2003, the system, included in Assets held for sale, generated a net lossesof approximately ($239,000) and ($92,000), respectively, and are immaterial forseparate presentation as a discontinued operation.

 

***Corporate Offices.***  We relocated our corporate offices in March2003.  In April 2003, we completed thesale of the building we previously occupied for net proceeds of $2.7 million,which resulted in a loss on the sale of ($383,000). 

 

***DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES***

 

The net loss recognized in earnings throughSale of residue gas and Sale of natural gas liquids during the first six monthsof 2003 from hedging activities was $19.5 million, and we did not recognize anylosses from hedge ineffectiveness. Overall, our hedges are expected to continue to be “highly effective”under SFAS No. 133 in the future.  Anadditional $2.8 million of losses were reclassified into earnings as a resultof the discontinuance of cash flow hedges. These cash flow hedges were discontinued due to the reduction offorecasted production volumes. 

 

8

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The gains and losses currently reflected inAccumulated other comprehensive income will be reclassified to earnings basedon the actual sales of the hedged gas or NGLs. Based on prices as of June 30, 2003, approximately $12.6 million of lossesin Accumulated other comprehensive income will be reclassified to earnings in2003 and approximately $746,000 of gains in Accumulated other comprehensiveincome will be reclassified to earnings in 2004.

 

***SUPPLEMENTARY CASHFLOW INFORMATION***

 

Interest paid was $13.7 million and $14.1million for the six months ended June 30, 2003 and 2002, respectively. A total of $6.0 million was paid in incometaxes in the six months ended June 30, 2003. No income taxes were paid during the six months ended June 30, 2002.

 

***STOCK COMPENSATION***

 

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

 

We are required to record compensationexpense (if not previously accrued) equal to the number of unexercisedre-priced options multiplied by the amount by which our stock price at the endof any quarter exceeds $21.00 per share. We had re-priced options covering 40,750 common shares outstanding atJune 30, 2003 and 63,583 common shares outstanding at June 30, 2002.  Based on our stock price at June 30, 2003 of$39.60 per share and our stock price at June 30, 2002 of $37.40 per share,compensation expense of $287,000 and $11,000, respectively, was recorded in thethree months ended June 30, 2003 and 2002 and $340,000 and $323,000,respectively was recorded in the six months ended June 30, 2003 and 2002.

 

SFAS No. 123 requires pro forma disclosuresfor each quarter that a statement of operations is presented.  The following is a summary of the options to purchase ourcommon stock granted during the quarters and six months ended June 30, 2003 and2002, respectively.

 
|                      |   | **Quarter Ended June 30,** |   | **Six Months Ended June 30,** |   |
|---------------------------|--------|----------------------------|--------|-------------------------------|--------|
|                      |   | **2003**                   |   | **2002**                      |   | **2003** |   | **2002** |   |
| 2002 Plan                 |   | 15,000                     |   | —                        |   | 45,000 |   | — |   |
| 2002 Directors’ Plan |   | 18,000                     |   | 18,000                        |   | 18,000 |   | 18,000 |   |
| Total options granted     |   | 33,000                     |   | 18,000                        |   | 63,000 |   | 18,000 |   |

 

The following is a summary of the weightedaverage fair value per share of the options granted during the quarters and six months ended June 30,2003 and 2002, respectively.

 
|                      |   | **Quarter Ended June 30,** |   | **Six Months Ended June 30,** |   |
|---------------------------|--------|----------------------------|--------|-------------------------------|--------|
|                      |   | **2003**                   |   | **2002**                      |   | **2003** |   | **2002** |   |
| 2002 Plan                 |   | $                          | 22.00  |                          | — |   | $ | 19.52 |   | — |   |
| 2002 Directors’ Plan |   | $                          | 21.39  |                          | $      | 22.50 |   | $ | 21.39 |   | $ | 22.50 |   |
|                           |        |                            |        |                               |        |  |  |  |  |  |  |  |  |

 

These values were estimated using theBlack-Scholes option-pricing model with the following assumptions:

 
|                            |   | **2002 Plan** |   | **2002 Directors’ Plan** |   |
|---------------------------------|--------|---------------|--------|-------------------------------|--------|
| Risk-free  interest rate        |   | 2.85          | %      | 2.59                          | %      |
| Expected  life (in years)       |   | 5             |   | 5                             |   |
| Expected  volatility            |   | 53            | %      | 54                            | %      |
| Expected  dividends (quarterly) |   | $             | 0.05   |                          | $      | 0.05 |   |
|                                 |        |               |        |                               |        |  |  |

 

9

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Under SFAS No. 123, the fair market value ofthe options at the grant date is amortized over the appropriate vesting periodfor purposes of calculating compensation expense.  If we had recorded compensation expense for our grants under ourstock-based compensation plans consistent with the fair value method under thispronouncement, our net income, income attributable to common stock, earningsper share of common stock and earnings per share of common stock - assumingdilution would approximate the pro forma amounts below (dollars in thousands,except per share amounts):

 
|                                                                                                                                          |   | **Quarter Ended June 30,** |
|-----------------------------------------------------------------------------------------------------------------------------------------------|--------|----------------------------|
|                                                                                                                                          |   | **2003**                   |   | **2003** |   | **2002** |   | **2002** |   |
|                                                                                                                                          |   | **As Reported**            |   | **Pro Forma** |   | **As Reported** |   | **Pro Forma** |   |
| Net income                                                                                                                                    |   | $                          | 20,900 |   | $ | 20,144 |   | $ | 13,766 |   | $ | 13,062 |   |
| Net income attributable to common stock                                                                                                       |   | 19,089                     |   | 18,333 |   | 11,636 |   | 10,932 |   |
| Earnings per  share of common stock                                                                                                           |   | 0.58                       |   | 0.55 |   | 0.35 |   | 0.34 |   |
| Earnings per share of common stock - assuming dilution                                                                                        |   | 0.56                       |   | 0.54 |   | 0.34 |   | 0.33 |   |
| Stock-based employee compensation cost, net of related tax effects,  included in net income                                                   |   | $                          | 241 |   | $ | — |   | $ | 28 |   | $ | — |   |
| Stock-based employee compensation cost, net of related tax effects,  includable in net income if the fair value based method had been applied |   | $                          | — |   | $ | 997 |   | $ | — |   | $ | 732 |   |

 
|                                                                                                                                          |   | **Six Months Ended June 30,** |
|-----------------------------------------------------------------------------------------------------------------------------------------------|--------|-------------------------------|
|                                                                                                                                          |   | **2003**                      |   | **2003** |   | **2002** |   | **2002** |   |
|                                                                                                                                          |   | **As Reported**               |   | **Pro Forma** |   | **As Reported** |   | **Pro Forma** |   |
| Net income                                                                                                                                    |   | $                             | 44,275 |   | $ | 42,755 |   | $ | 21,766 |   | $ | 20,460 |   |
| Net income attributable to common stock                                                                                                       |   | 40,652                        |   | 39,132 |   | 17,506 |   | 16,200 |   |
| Earnings per  share of common stock                                                                                                           |   | 1.23                          |   | 1.18 |   | 0.53 |   | 0.49 |   |
| Earnings per share of common stock - assuming dilution                                                                                        |   | 1.19                          |   | 1.15 |   | 0.52 |   | 0.48 |   |
| Stock-based employee compensation cost, net of related tax effects,  included in net income                                                   |   | $                             | 334 |   | $ | — |   | $ | 321 |   | $ | — |   |
| Stock-based employee compensation cost, net of related tax effects,  includable in net income if the fair value based method had been applied |   | $                             | — |   | $ | 1,854 |   | $ | — |   | $ | 1,627 |   |

 

***SEGMENT REPORTING***

 

We operate in four principal businesssegments, as follows:  Gas Gathering,Processing and Treating; Exploration and Production; Marketing; andTransportation.  Management separatelymonitors these segments for performance against our internal forecast and thesesegments are consistent 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 ofour Exploration and Production segment) to our gathering systems for deliveryto our processing or treating plants, process the natural gas to extract NGLsand treat the natural gas in order to meet pipeline specifications.  In some areas, where no processing isrequired, we gather and compress producers’ gas and deliver it to pipelines forfurther delivery to market.  Except forvolumes taken in kind by our producers, the Marketing segment sells the residuegas and NGLs extracted at most of our facilities.  In this segment, we recognize revenue for our services at thetime the service is performed.

 

Substantially all gas flowing through ourgathering, processing and treating facilities is supplied under three types ofcontracts providing for the purchase, treating or processing of natural gas forperiods ranging from one month to twenty years or in some cases for the life ofthe oil and gas lease.  Approximately81% of our plant facilities’ gross margins, or revenues at the plants lessproduct purchases, for the month of June 2003 resulted frompercentage-of-proceeds agreements in which we

 

10

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are typically responsible for the marketingof the gas and NGLs.  We pay producers aspecified percentage of the net proceeds received from the sale of the gas andthe NGLs.

 

Approximately 11% of our plant facilities’gross margins for the month of June 2003 resulted from contracts that areprimarily fee-based from which we receive a set fee for each Mcf of gas gatheredand/or processed. This type of contract provides us with a steady revenuestream that is not dependent on commodity prices, except to the extent that lowprices may cause a producer to delay drilling.

 

Approximately 8% of our plant facilities’gross margins for the month of June 2003 resulted from contracts with‘‘keepwhole’’ arrangements or wellhead purchase contracts.  We retain the NGLs recovered by theprocessing 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 ofthe contracts permits us to benefit when the value of the NGLs is greater as aliquid than as a portion of the residue gas stream.  However, we are adversely affected when the value of the NGLs islower as a liquid than as a portion of the residue gas stream.

 

***Exploration andProduction.*** The activities of the Exploration and Production segment include theexploration and development of gas properties in the Rocky Mountain area,including those where our gathering and/or processing facilities arelocated.  The Marketing segment sellsthe majority of the production from these properties.

 

***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 sales price.  This segment also markets gas and NGLsproduced by our gathering, processing, treating and production assets.  Also included in this segment are ourCanadian marketing operations, which are conducted through our wholly-ownedsubsidiary WGR – Canada, Inc. and are immaterial for separate presentation.

 

In this segment, revenues for sales ofproduct are recognized at the time the gas or NGLs are delivered to thecustomer and are sensitive to changes in the market prices of the underlyingcommodities.  Revenues for sales ofproduct are recognized at the time the gas or NGLs are delivered to thecustomer and are sensitive to changes in the market prices of the underlyingcommodities.  We record revenue on ourphysical gas and NGL marketing activities on a gross basis versus sales net ofpurchases basis.  We believe that thispresentation is required because we obtain title to all the gas and NGLs thatwe buy including third-party purchases, bear the risk of loss and creditexposure on these transactions and it is our intention upon entering thesecontracts to take physical delivery of the product. We sell our products underagreements with varying terms and conditions in order to match seasonal andother changes in demand.

 

***Transportation.***  The Transportation segment reflects theoperations of Western’s MIGC and MGTC pipelines.  The revenue generated in this segment is primarily fromtransportation 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.

 

***Segment Information.***  The following table sets forth our segmentinformation as of and for the three and six months ended June 30, 2003 and 2002(dollars in thousands).  Due to ourintegrated operations, the use of allocations in the determination of businesssegment information is necessary. Inter-segment revenues are valued at prices comparable to those ofunaffiliated customers.

 
|                                             |   | **Gas  Gathering  and  Processing** |    | **Exploration  and  Production** |   | **Marketing** |   | **Trans-  portation** |    | **Corporate** |   | **Elim-  inating  Entries** |   | **Total** |    |
|--------------------------------------------------|--------|-------------------------------------|---------|----------------------------------|--------|---------------|--------|-----------------------|---------|---------------|--------|-----------------------------|--------|-----------|---------|
| **Quarter Ended June 30, 2003**                  |   |                                |    |                             |   |          |   |                  |    |          |   |                        |   |      |    |
| Revenues from unaffiliated customers             |   |                                |    |                             |   |          |   |                  |    |          |   |                        |   |      |    |
| Sale of gas                                      |   | $                                   | 862     |                             | $      | 2,397         |   | $                     | 555,988 |          | $      | 138                         |   | $         | —  |   | $ | — |   | $ | 559,385 |   |
| Sale of natural gas liquids                      |   | 2                                   |    | —                           |   | 82,589        |   | —                |    |          |   |                        |   | 82,591    |    |
| Equity hedges:                                   |   |                                |    |                             |   |          |   |                  |    |          |   |                        |   |      |    |
| Residue                                          |   | (593                                | )       | (4,702                           | )      | —        |   | —                |    | —        |   | —                      |   | (5,295    | )       |
| Liquids                                          |   | (2,081                              | )       | —                           |   | —        |   | —                |    | —        |   | —                      |   | (2,081    | )       |
| Gathering, processing and transportation revenue |   | 19,911                              |    | —                           |   | —        |   | 1,691                 |    | (144          | )      | —                      |   | 21,458    |    |
| Total revenues from unaffiliated customers       |   | 18,101                              |    | (2,305                           | )      | 638,577       |   | 1,829                 |    | (144          | )      | —                      |   | 656,058   |    |
| Inter-segment revenues                           |   | 261,915                             |    | 52,608                           |   | 8,010         |   | 3,356                 |    | (7            | )      | (325,882                    | )      | —    |    |
| Non-cash change in fair value of derivatives     |   | 254                                 |    | 263                              |   | 3,166         |   | —                |    | —        |   | —                      |   | 3,683     |    |
| Interest income                                  |   | —                              |    | 5                                |   | —        |   | (2                    | )       | 3,090         |   | (2,989                      | )      | 104       |    |
| Other, net                                       |   | (434                                | )       | 960                              |   | 281           |   | —                |    | (161          | )      | —                      |   | 646       |    |
| Total revenues                                   |   | 279,836                             |    | 51,531                           |   | 650,034       |   | 5,183                 |    | 2,778         |   | (328,871                    | )      | 660,491   |    |
| Product purchases                                |   | 232,599                             |    | 646                              |   | 640,742       |   | —                |    | 76            |   | (314,227                    | )      | 559,836   |    |
| Plant operating and transportation expense       |   | 21,251                              |    | 110                              |   | 79            |   | 2,300                 |    | (441          | )      | (687                        | )      | 22,612    |    |
| Oil and gas exploration and production expense   |   | —                              |    | 21,332                           |   | —        |   | —                |    | —        |   | (8,042                      | )      | 13,290    |    |
| Earnings from equity investments                 |   | (1,867                              | )       | —                           |   | —        |   | —                |    | —        |   | —                      |   | (1,867    | )       |
| Operating profit                                 |   | 27,853                              |    | 29,443                           |   | 9,213         |   | 2,883                 |    | 3,143         |   | (5,915                      | )      | 66,620    |    |
|                                             |   |                                |    |                             |   |          |   |                  |    |          |   |                        |   |      |    |
| Depreciation, depletion and amortization         |   | 6,693                               |    | 8,498                            |   | 36            |   | 430                   |    | 2,028         |   | —                      |   | 17,685    |    |
| Selling and administrative expense               |   | 4,296                               |    | 2,937                            |   | 1,856         |   | 834                   |    | —        |   | —                      |   | 9,923     |    |
| (Gain) loss from sale of assets                  |   | 246                                 |    | —                           |   | —        |   | (118                  | )       | (323          | )      | —                      |   | (195      | )       |
| Interest expense                                 |   | —                              |    | —                           |   | —        |   | —                |    | 6,429         |   | —                      |   | 6,429     |    |
| Segment profit                                   |   | $                                   | 16,618  |                             | $      | 18,008        |   | $                     | 7,321   |          | $      | 1,737                       |   | $         | (4,991  | ) | $ | (5,915 | ) | $ | 32,778 |   |
|                                             |   |                                |    |                             |   |          |   |                  |    |          |   |                        |   |      |    |
| Identifiable assets                              |   |                                |    |                             |   |          |   |                  |    |          |   |                        |   |      |    |
| Other allocated assets                           |   | $                                   | —  |                             | $      | 3,633         |   | $                     | 132,235 |          | $      | 1,601                       |   | $         | 375,185 |   | $ | (57,519 | ) | $ | 455,135 |   |
| Investment in others                             |   | 3,028                               |    | —                           |   | —        |   | 3,789                 |    | 54,783        |   | (36,028                     | )      | 25,572    |    |
| Capital assets                                   |   | 589,299                             |    | 229,250                          |   | 1,602         |   | 41,536                |    | 55,777        |   | 7                           |   | 917,471   |    |
| Total identifiable assets                        |   | $                                   | 592,327 |                             | $      | 232,883       |   | $                     | 133,837 |          | $      | 46,926                      |   | $         | 485,745 |   | $ | (93,540 | ) | $ | 1,398,178 |   |

 

11

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|                                             |   | **Gathering  and  Processing** |    | **Exploration  and  Production** |   | **Marketing** |   | **Trans-  portation** |    | **Corporate** |   | **Elim-  inating  Entries** |   | **Total** |       |
|--------------------------------------------------|--------|--------------------------------|---------|----------------------------------|--------|---------------|--------|-----------------------|---------|---------------|--------|-----------------------------|--------|-----------|------------|
| **Quarter Ended June 30, 2002**                  |   |                           |    |                             |   |          |   |                  |    |          |   |                        |   |      |       |
| Revenues from unaffiliated customers             |   |                           |    |                             |   |          |   |                  |    |          |   |                        |   |      |       |
| Sale of gas                                      |   | $                              | 564     |                             | $      | 349           |   | $                     | 502,285 |          | $      | 259                         |   | $         | —     |   | $ | — |   | $ | 503,457 |   |
| Sale of natural gas liquids                      |   | 3                              |    | —                           |   | 83,274        |   | —                |    | —        |   | —                      |   | 83,277    |       |
| Equity hedges:                                   |   |                           |    |                             |   |          |   |                  |    |          |   |                        |   |      |       |
| Residue                                          |   | 650                            |    | 6,090                            |   | —        |   | —                |    | —        |   | —                      |   | 6,740     |       |
| Liquids                                          |   | (3,410                         | )       | —                           |   | —        |   | —                |    | —        |   | —                      |   | (3,410    | )          |
| Gathering, processing and transportation revenue |   | 12,932                         |    | —                           |   | —        |   | 2,045                 |    | 51            |   | —                      |   | 15,028    |       |
| Total revenues from unaffiliated customers       |   | 10,739                         |    | 6,439                            |   | 585,559       |   | 2,311                 |    | 51            |   | —                      |   | 605,099   |       |
| Inter-segment revenues                           |   | 162,582                        |    | 25,782                           |   | 5,866         |   | 3,728                 |    | 13            |   | (197,971                    | )      | —    |       |
| Non-cash change in fair value of derivatives     |   | —                         |    | —                           |   | 7,866         |   | —                |    | —        |   | —                      |   | 7,866     |       |
| Interest income                                  |   | —                         |    | 14                               |   | 10            |   | —                |    | 2,068         |   | (2,027                      | )      | 65        |       |
| Other, net                                       |   | 1,344                          |    | 36                               |   | —        |   | 2                     |    | (277          | )      | —                      |   | 1,105     |       |
| Total revenues                                   |   | 174,665                        |    | 32,271                           |   | 599,301       |   | 6,041                 |    | 1,854         |   | (199,998                    | )      | 614,128   |       |
| Product purchases                                |   | 132,850                        |    | 756                              |   | 585,788       |   | —                |    | (154          | )      | (190,951                    | )      | 528,289   |       |
| Plant operating and transportation expense       |   | 17,168                         |    | 34                               |   | 79            |   | 2,834                 |    | (2            | )      | (323                        | )      | 19,790    |       |
| Oil and gas exploration and production expense   |   | —                         |    | 15,534                           |   | —        |   | —                |    | —        |   | (6,392                      | )      | 9,142     |       |
| Earnings from equity investments                 |   | (802                           | )       | —                           |   | —        |   | —                |    | —        |   | —                      |   | (802      | )          |
| Operating profit                                 |   | 25,448                         |    | 15,947                           |   | 13,434        |   | 3,207                 |    | 2,010         |   | (2,332                      | )      | 57,709    |       |
|                                             |   |                           |    |                             |   |          |   |                  |    |          |   |                        |   |      |       |
| Depreciation, depletion and amortization         |   | 10,363                         |    | 4,784                            |   | 40            |   | 425                   |    | 1,631         |   | —                      |   | 17,243    |       |
| Selling and administrative expense               |   | 5,254                          |    | 3,333                            |   | 2,425         |   | 975                   |    | —        |   | —                      |   | 11,887    |       |
| (Gain)Loss from sale of assets                   |   | —                         |    | (59                              | )      | —        |   | —                |    | 132           |   | —                      |   | 73        |       |
| Interest expense                                 |   | —                         |    | —                           |   | —        |   | —                |    | 6,770         |   | —                      |   | 6,770     |       |
| Segment profit                                   |   | $                              | 9,831   |                             | $      | 7,989         |   | $                     | 10,969  |          | $      | 1,807                       |   | $         | (6,523     | ) | $ | (2,332 | ) | $ | 21,736 |   |
|                                             |   |                           |    |                             |   |          |   |                  |    |          |   |                        |   |      |       |
| Identifiable assets                              |   |                           |    |                             |   |          |   |                  |    |          |   |                        |   |      |       |
| Other allocated assets                           |   | $                              | 1,293   |                             | $      | 12,491        |   | $                     | 111,601 |          | $      | 844                         |   | $         | 376,995    |   | $ | (55,264 | ) | $ | 447,960 | ** ** |
| Investment in others                             |   | 1,960                          |    | —                           |   | —        |   | 3,549                 |    | 46,448        |   | (37,266                     | )      | 14,691    | ** ** |
| Capital assets                                   |   | 542,030                        |    | 203,039                          |   | 1,749         |   | 42,752                |    | 42,752        |   | —                      |   | 839,493   | ** ** |
| Total identifiable assets                        |   | $                              | 545,283 |                             | $      | 215,530       |   | $                     | 113,350 |          | $      | 47,145                      |   | $         | 473,366    |   | $ | (92,530 | ) | $ | 1,302,144 | ** ** |

 

12

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|                                             |   | **Gas  Gathering  and  Processing** |    | **Exploration  and  Production** |   | **Marketing** |   | **Trans-  portation** |      | **Corporate** |   | **Elim-  inating  Entries** |   | **Total** |    |
|--------------------------------------------------|--------|-------------------------------------|---------|----------------------------------|--------|---------------|--------|-----------------------|-----------|---------------|--------|-----------------------------|--------|-----------|---------|
| **Six Months Ended June 30, 2003**               |   |                                |    |                             |   |          |   |                  |      |          |   |                        |   |      |    |
| Revenues from unaffiliated customers             |   |                                |    |                             |   |          |   |                  |      |          |   |                        |   |      |    |
| Sale of gas                                      |   | $                                   | 1,935   |                             | $      | 2,114         |   | $                     | 1,342,400 |          | $      | 434                         |   | $         | —  |   | $ | — |   | $ | 1,346,883 |   |
| Sale of natural gas liquids                      |   | 6                                   |    | —                           |   | 179,526       |   | —                |      |          |   |                        |   | 179,532   |    |
| Equity hedges:                                   |   |                                |    |                             |   |          |   |                  |      |          |   |                        |   |      |    |
| Residue                                          |   | (1,561                              | )       | (11,493                          | )      | —        |   | —                |      | —        |   | —                      |   | (13,054   | )       |
| Liquids                                          |   | (6,973                              | )       | —                           |   | —        |   | —                |      | —        |   | —                      |   | (6,973    | )       |
| Gathering, processing and transportation revenue |   | 37,815                              |    | —                           |   | —        |   | 3,529                 |      | (109          | )      | —                      |   | 41,235    |    |
| Total revenues from unaffiliated customers       |   | 31,222                              |    | (9,379                           | )      | 1,521,926     |   | 3,963                 |      | (109          | )      | —                      |   | 1,547,623 |    |
| Inter-segment revenues                           |   | 563,684                             |    | 117,152                          |   | 19,041        |   | 7,231                 |      | 27            |   | (707,135                    | )      | —    |    |
| Non-cash change in fair value of derivatives     |   | (470                                | )       | (1,835                           | )      | 1,825         |   | —                |      | —        |   | —                      |   | (480      | )       |
| Interest income                                  |   | —                              |    | 13                               |   | —        |   | —                |      | 5,512         |   | (5,338                      | )      | 187       |    |
| Other, net                                       |   | (3                                  | )       | 989                              |   | 281           |   | —                |      | —        |   | —                      |   | 1,267     |    |
| Total revenues                                   |   | 594,433                             |    | 106,940                          |   | 1,543,073     |   | 11,194                |      | 5,430         |   | (712,473                    | )      | 1,548,597 |    |
| Product purchases                                |   | 496,947                             |    | 1,040                            |   | 1,518,670     |   | —                |      | 208           |   | (685,427                    | )      | 1,331,438 |    |
| Plant operating and transportation expense       |   | 41,225                              |    | 288                              |   | 159           |   | 4,265                 |      | 90            |   | (1,493                      | )      | 44,534    |    |
| Oil and gas exploration and production expense   |   | —                              |    | 42,893                           |   | —        |   | —                |      | —        |   | (17,092                     | )      | 25,801    |    |
| Earnings from equity investments                 |   | (3,429                              | )       | —                           |   | —        |   | —                |      | —        |   | —                      |   | (3,429    | )       |
| Operating profit                                 |   | 59,690                              |    | 62,719                           |   | 24,244        |   | 6,929                 |      | 5,132         |   | (8,461                      | )      | 150,253   |    |
|                                             |   |                                |    |                             |   |          |   |                  |      |          |   |                        |   |      |    |
| Depreciation, depletion and amortization         |   | 14,588                              |    | 16,558                           |   | 71            |   | 863                   |      | 3,748         |   | —                      |   | 35,828    |    |
| Selling and administrative expense               |   | 9,031                               |    | 6,178                            |   | 3,910         |   | 1,395                 |      | —        |   | —                      |   | 20,515    |    |
| (Gain) loss from sale of assets                  |   | 154                                 |    | —                           |   | —        |   | (118                  | )         | 50            |   | —                      |   | 86        |    |
| Interest expense                                 |   | —                              |    | —                           |   | —        |   | —                |      | 13,243        |   | —                      |   | 13,243    |    |
| Segment profit                                   |   | $                                   | 35,917  |                             | $      | 39,983        |   | $                     | 20,263    |          | $      | 4,789                       |   | $         | (11,909 | ) | $ | (8,461 | )  | $ | 80,581 |   |
|                                             |   |                                |    |                             |   |          |   |                  |      |          |   |                        |   |      |    |
| Identifiable assets                              |   |                                |    |                             |   |          |   |                  |      |          |   |                        |   |      |    |
| Other allocated assets                           |   | $                                   | —  |                             | $      | 3,633         |   | $                     | 132,235   |          | $      | 1,601                       |   | $         | 375,185 |   | $ | (57,519 | ) | $ | 455,135 |   |
| Investment in others                             |   | 3,028                               |    | —                           |   | —        |   | 3,789                 |      | 54,783        |   | (36,028                     | )      | 25,572    |    |
| Capital assets                                   |   | 589,299                             |    | 229,250                          |   | 1,602         |   | 41,536                |      | 55,777        |   | 7                           |   | 917,471   |    |
| Total identifiable assets                        |   | $                                   | 592,327 |                             | $      | 232,883       |   | $                     | 133,837   |          | $      | 46,926                      |   | $         | 485,745 |   | $ | (93,540 | ) | $ | 1,398,178 |   |

 

13

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|                                             |   | **Gathering  and  Processing** |    | **Exploration  and  Production** |   | **Marketing** |   | **Trans-  portation** |      | **Corporate** |   | **Elim-  inating  Entries** |   | **Total** |    |
|--------------------------------------------------|--------|--------------------------------|---------|----------------------------------|--------|---------------|--------|-----------------------|-----------|---------------|--------|-----------------------------|--------|-----------|---------|
| **Six Months Ended June 30, 2002**               |   |                           |    |                             |   |          |   |                  |      |          |   |                        |   |      |    |
| Revenues from unaffiliated customers             |   |                           |    |                             |   |          |   |                  |      |          |   |                        |   |      |    |
| Sale of gas                                      |   | $                              | 879     |                             | $      | 601           |   | $                     | 1,036,668 |          | $      | 780                         |   | $         | —  |   | $ | — |   | $ | 1,038,928 |   |
| Sale of natural gas liquids                      |   | 6                              |    | —                           |   | 148,720       |   | —                |      | —        |   | —                      |   | 148,726   |    |
| Equity hedges:                                   |   |                           |    |                             |   |          |   |                  |      |          |   |                        |   |      |    |
| Residue                                          |   | 2,348                          |    | 14,511                           |   | —        |   | —                |      | —        |   | —                      |   | 16,859    |    |
| Liquids                                          |   | (4,052                         | )       | —                           |   | —        |   | —                |      | —        |   | —                      |   | (4,052    | )       |
| Gathering, processing and transportation revenue |   | 26,105                         |    | —                           |   | —        |   | 4,304                 |      | 50            |   | —                      |   | 30,459    |    |
| Total revenues from unaffiliated customers       |   | 25,286                         |    | 15,112                           |   | 1,185,388     |   | 5,084                 |      | 50            |   | —                      |   | 1,230,920 |    |
| Inter-segment revenues                           |   | 283,913                        |    | 45,594                           |   | 9,426         |   | 7,857                 |      | 27            |   | (346,817                    | )      | —    |    |
| Non-cash change in fair value of derivatives     |   | —                         |    | —                           |   | (3,129        | )      | —                |      | —        |   | —                      |   | (3,129    | )       |
| Interest income                                  |   | —                         |    | 24                               |   | 10            |   | —                |      | 3,895         |   | (3,827                      | )      | 102       |    |
| Other, net                                       |   | 2,119                          |    | 19                               |   | —        |   | 14                    |      | (1            | )      | —                      |   | 2,151     |    |
| Total revenues                                   |   | 311,318                        |    | 60,749                           |   | 1,191,695     |   | 12,955                |      | 3,971         |   | (350,644                    | )      | 1,230,044 |    |
| Product purchases                                |   | 235,147                        |    | 1,281                            |   | 1,170,158     |   | —                |      | 168           |   | (333,859                    | )      | 1,072,895 |    |
| Plant operating and transportation expense       |   | 33,593                         |    | 90                               |   | 132           |   | 5,449                 |      | (2            | )      | (601                        | )      | 38,661    |    |
| Oil and gas exploration and production expense   |   | —                         |    | 28,580                           |   | —        |   | —                |      | —        |   | (12,049                     | )      | 16,531    |    |
| Earnings from equity investments                 |   | (1,652                         | )       | —                           |   | —        |   | —                |      | —        |   | —                      |   | (1,652    | )       |
| Operating profit                                 |   | 44,230                         |    | 30,798                           |   | 21,405        |   | 7,506                 |      | 3,805         |   | (4,135                      | )      | 103,609   |    |
|                                             |   |                           |    |                             |   |          |   |                  |      |          |   |                        |   |      |    |
| Depreciation, depletion and amortization         |   | 20,959                         |    | 10,105                           |   | 80            |   | 860                   |      | 3,185         |   | —                      |   | 35,189    |    |
| Selling and administrative expense               |   | 9,095                          |    | 5,597                            |   | 4,198         |   | 1,687                 |      | —        |   | —                      |   | 20,578    |    |
| (Gain) Loss from sale of assets                  |   | 3                              |    | (59                              | )      | —        |   | 6                     |      | 132           |   | —                      |   | 82        |    |
| Interest expense                                 |   | —                         |    | —                           |   | —        |   | —                |      | 13,430        |   |                        |   | 13,430    |    |
| Segment profit                                   |   | $                              | 14,172  |                             | $      | 15,156        |   | $                     | 17,127    |          | $      | 4,953                       |   | $         | (12,942 | ) | $ | (4,135 | ) | $ | 34,330 |   |
|                                             |   |                           |    |                             |   |          |   |                  |      |          |   |                        |   |      |    |
| Identifiable assets                              |   |                           |    |                             |   |          |   |                  |      |          |   |                        |   |      |    |
| Other allocated assets                           |   | $                              | 1,293   |                             | $      | 12,491        |   | $                     | 111,601   |          | $      | 844                         |   | $         | 376,995 |   | $ | (55,264 | ) | $ | 447,960 |   |
| Investment in others                             |   | 1,960                          |    | —                           |   | —        |   | 3,549                 |      | 46,448        |   | (37,266                     | )      | 14,691    |    |
| Capital assets                                   |   | 542,030                        |    | 203,039                          |   | 1,749         |   | 42,752                |      | 42,752        |   | —                      |   | 839,493   |    |
| Total identifiable assets                        |   | $                              | 545,283 |                             | $      | 215,530       |   | $                     | 113,350   |          | $      | 47,145                      |   | $         | 473,366 |   | $ | (92,530 | ) | $ | 1,302,144 |   |

 

***LEGALPROCEEDINGS***

 

Reference**is made to“Part II - Other Information - Item 1. Legal Proceedings,” of this Form 10-Q.**

 

***RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS***

*** ***

**SFAS No. 141 and SFAS No. 142.**  In June 2001, the Financial AccountingStandards Board, or FASB issued SFAS No. 141, “Business Combinations”, and SFASNo. 142 “Goodwill and Intangible Assets.” SFAS No. 141 requires all business combinations initiated after June 30,2001 to be accounted for using the purchase method.  Additionally, SFAS No. 141 requires companies to disaggregate andreport separately from goodwill certain intangible assets.  SFAS No. 142 establishes new guidelines foraccounting for goodwill and other intangible assets.  Under SFAS No. 142, goodwill and certain other intangible assetsare not amortized, but rather are reviewed annually for impairment.  The FASB, the Securities and ExchangeCommission and others continue to discuss the appropriate application of SFASNo. 141 and No. 142 to oil and gas mineral rights held under lease and othercontractual arrangements representing the right to extract such reserves.  Depending on the outcome of suchdiscussions, these oil and gas mineral rights held under lease and othercontractual arrangements representing the right to extract such reserves forboth undeveloped and developed leaseholds may be classified separately from oiland gas properties as intangible assets on our balance sheet.  In addition, the disclosures required bySFAS No. 141 and No. 142 relative to intangibles would be included in the notesto financial statements.  Historically,we, like many other oil and gas companies, have included these oil and gasmineral rights held under lease and other contractual arrangements representingthe right to extract these reserves as part of the oil and gas properties, evenafter SFAS No. 141 and No. 142 became effective.

 

This interpretation of SFAS No. 141 and No. 142 would only affect ourbalance sheet classification of oil and gas leaseholds.  Our results of operations and cash flowswould not be affected, since these oil and gas mineral rights and othercontractual arrangements representing the right to extract such reserves wouldcontinue to be amortized in accordance with the accounting rules for oil and gascompanies provided in SFAS No. 19, “Financial Accounting and Reporting by Oiland Gas Producing Companies”.

 

At June 30, 2003, we have undeveloped leaseholds of $47.6 million thatwould be classified on our balance sheet as “intangible undeveloped leaseholds”and developed leaseholds of approximately $18.3 million that would beclassified as “intangible developed leaseholds” if we applied theinterpretation currently being discussed.

 

We will continue to classifyour oil and gas mineral rights held under lease and other contractualarrangements representing the right to extract such reserves as tangible oiland gas properties until further guidance is provided.

 

 

14

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FIN 46. In January 2003, the FASB issued Interpretation No. 46, or “FIN 46”,“Consolidation of Variable Interest Entities.” FIN 46 provides guidance on how to identify a variable interest entity,or VIE, and determine when the assets, liabilities, and results of operationsof a VIE need to be included in a company’s consolidated financialstatements.  FIN 46 also requiresadditional disclosures by primary beneficiaries and other significant variableinterest holders in a VIE.  Theprovisions of FIN 46 are effective immediately for all VIEs created afterJanuary 31, 2003.  For VIEs createdbefore February 1, 2003, the provisions of FIN 46 must be adopted at thebeginning of the first interim or annual reporting period beginning after June15, 2003.   We do not have an interestin any entities that would be considered VIEs, and therefore the adoption of this pronouncement did not have animpact on our earnings or financial position.

 

SFAS No. 149.  In April 2003, the FASB issued SFAS No. 149, “Amendment ofStatement 133 on Derivative Instruments and Hedging Activities.”  SFAS No. 149 is effective for contractsentered into or modified after June 30, 2003. This statement amends and clarifies financial accounting reporting forderivative instruments and for hedging activities under SFAS Statement No. 133,“Accounting for Derivative Instruments and Hedging Activities.”  We will adopt SFAS No. 149 as required bythe pronouncement.  We do not expect theadoption of this pronouncement to have an impact on our earings or financialposition.

 

SFAS No. 150.  In May 2003, the FASB issued SFAS No. 150, “Accounting forCertain Financial Instruments with Characteristics of Both Liabilities andEquity.”  SFAS No. 150 is effective for instrumentsentered into or modified after May 31, 2003 and is otherwise effective at thebeginning of the first interim period beginning after June 15, 2003.  This statement establishes standards forclassifying and measuring financial instruments of both liabilities and equity.  We adopted SFAS No. 150 on June 1,2003.  The adoption of thispronouncement did not have an impact on our financial statements as we do nothave any instruments that were the subject of this pronouncement.

 

15

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

 

The following discussion and analysis relatesto factors which have affected our consolidated financial condition and resultsof operations for the three and six months ended June 30, 2003 and 2002.   Prior year amounts have been reclassifiedas appropriate to conform to the presentation used in 2003.  You should also refer to our interimconsolidated financial statements and notes included in “Part 1 –FinancialInformation –Item 1. Financial Statements” of this report.  This section, as well as other sections inthis Quarterly Report on 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 factors referredto herein, numerous factors affecting the gas processing or the oil and gasindustry generally and in the specific markets for gas and NGLs in which weoperate could cause actual results to differ materially from those in suchforward-looking statements.

 

***Results of Operations***

 

**Threeand six months ended June 30, 2003 compared to the three and six months endedJune 30, 2002**

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

 
|                                          |   | **Three  Months Ended  June 30,** |       | **Percent  Change** |       | **Six Months  Ended  June 30,** |       | **Percent  Change** |       |
|-----------------------------------------------|--------|-----------------------------------|------------|---------------------|------------|---------------------------------|------------|---------------------|------------|
| **2003**                                      |   | **2002**                          | **2003**   |                | **2002**   |
|                                          |   |                              | ** ** |                | ** ** |                            | ** ** |                | ** ** |   | ** ** |   | ** ** |
| **Financial results:**                        |   |                              |       |                |       |                            |       |                |       |   |   |   |   |
| Revenues                                      |   | $                                 | 660,491    |                | $          | 614,128                         |       | 8                   |       | $ | 1,548,597 |   | $ | 1,230,044 |   | 26 |   |
| Gross profit                                  |   | 49,130                            |       | 40,393              |       | 22                              |       | 114,339             |       | 68,338 |   | 67 |   |
| Net income                                    |   | 20,900                            |       | 13,766              |       | 52                              |       | 44,275              |       | 21,766 |   | 103 |   |
| Earnings per share of common stock            |   | .58                               |       | .35                 |       | 66                              |       | 1.23                |       | .53 |   | 132 |   |
| Earnings  per share of common stock - diluted |   | .56                               |       | .34                 |       | 65                              |       | 1.19                |       | .52 |   | 129 |   |
| Net cash provided by operating activities     |   | $                                 | 26,495     |                | $          | 45,390                          |       | (42                 | )          | $ | 141,650 |   | $ | 67,915 |   | 109 |   |
|                                          |   |                              |       |                |       |                            |       |                |       |   |   |   |   |
| **Operating data:**                           |   |                              |       |                |       |                            |       |                |       |   |   |   |   |
| Average gas sales (MMcf/D)                    |   | 1,247                             |       | 1,856               |       | (33                             | )          | 1,419               |       | 2,148 |   | (34 | ) |
| Average  NGL sales (MGal/D)                   |   | 1,626                             |       | 2,118               |       | (23                             | )          | 1,640               |       | 2,031 |   | (19 | ) |
| Average gas prices ($/Mcf)                    |   | $                                 | 4.86       |                | $          | 3.02                            |       | 61                  |       | $ | 5.18 |   | $ | 2.71 |   | 91 |   |
| Average NGL prices ($/Gal)                    |   | $                                 | .54        |                | $          | .41                             |       | 32                  |       | $ | .58 |   | $ | .39 |   | 49 |   |

 

Net income increased $7.1millionand $22.5 million for the three and six months ended June 30, 2003 compared tothe same periods in 2002.  The increasesin net income were primarily attributable to a significant increase in gas andNGL prices in 2003 compared to the same periods last year.  This increase in prices was supplemented byincreased equity production from the Powder River Basin coal bed methanedevelopment and the Green River Basin. Partially offsetting the increases to net income in the six months endedJune 30, 2003 was a pre-tax loss of $2.8 million from the discontinuance ofhedge treatment on some financial instruments and a $6.7 millionafter-tax loss from theCumulative effect of a change in accounting principle from the adoption of SFASNo. 143 “Accounting for Asset Retirement Obligations” on January 1, 2003.

 

Revenues from the sale of gas increased $43.9million to $554.1 million for the three months ended June 30, 2003 compared tothe same period in 2002.  This increasewas primarily due to an increase in product prices, which more than offset adecrease in sales volume in the three months ended June 30, 2003.  Average gas prices realized by us increased$1.84 per Mcf to $4.86 per Mcf for the quarter ended June 30, 2003 compared tothe same period in 2002.  Included inthe realized gas price were approximately $5.3 million of losses recognized inthe three months ended June 30, 2003 related to futures positions on equity gasvolumes.  We have entered intoadditional futures positions for approximately half of our equity gas for theremainder of 2003 and to a lesser extent in 2004.  See further discussion in “Item 3. Quantitative and QualitativeDisclosures About Market Risk”.  Averagegas sales volumes decreased to 1,247 MMcf per day for the quarter ended June30, 2003 compared to the same period in 2002. This decrease was due to a temporary reduction in third party salesvolume resulting from the increase in product prices and related creditexposure.

 

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Revenues from the sale of gas increased$278.0 million to $1,333.8 million for the six months ended June 30, 2003compared to the same period in 2002. This increase was primarily due to an increase in product prices, whichmore than offset a decrease in sales volume in the six months ended June 30,2003.  Average gas prices realized by usincreased $2.47 per Mcf to $5.18 per Mcf for the six months ended June 30, 2003compared to the same period in 2002. Included in the realized gas price were approximately $13.1 million oflosses recognized in the six months ended June 30, 2003 related to futurespositions on equity gas volumes.  Wehave entered into additional futures positions for approximately half of ourequity gas for the remainder of 2003 and to a lesser extent in 2004.  See further discussion in “Item 3.Quantitative and Qualitative Disclosures About Market Risk”.  Average gas sales volumes decreased to 1,419MMcf per day for the six months ended June 30, 2003 compared to the same periodin 2002.  This decrease was due to atemporary reduction in third party sales volume resulting from the increase inproduct prices and related credit exposure.

 

Revenues from the sale of NGLs remainrelatively constant at $80.5 million for the three months ended June 30, 2003compared to the same period in 2002. This is primarily due to a significant increase in product prices thatwas substantially 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 $0.13 per gallon to $0.54per gallon for the three months ended June 30, 2003 compared to the same periodin 2002.  Included in the realized NGLprice were approximately $2.1 million of losses recognized in the three monthsended June 30, 2003 related to futures positions on equity NGL volumes.  We have entered into additional futurespositions for the majority of our equity NGL production for the remainder of2003 and to a lesser extent in 2004. See further discussion in “Item 3. Quantitative and QualitativeDisclosures About Market Risk”.  AverageNGL sales volumes decreased 492 MGal per day to 1,626 MGal per day for thethree months ended June 30, 2003 compared to the same period in 2002.

 

Revenues from the sale of NGLs increasedapproximately $27.9 million to $172.6 million for the six months ended June 30,2003 compared to the same period in 2002. This increase is primarily due to a significant increase in productprices, which was partially offset by a reduction in sales volumes as a resultof the sale of our Toca facility in September 2002.  Average NGL prices realized by us increased $0.19 per gallon to$0.58 per gallon for the six months ended June 30, 2003 compared to the sameperiod in 2002.  Included in therealized NGL price were approximately $7.0 million of losses recognized in thesix months ended June 30, 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 and to a lesser extent in 2004.  See further discussion in “Item 3. Quantitative and QualitativeDisclosures About Market Risk”.  AverageNGL sales volumes decreased 391 MGal per day to 1,640 MGal per day for the sixmonths ended June 30, 2003 compared to the same period in 2002.

 

Product purchases increased by $31.5 millionand $258.5 million for the quarter and six months ended June 30, 2003 comparedto the same periods in 2002 as a result of the significant increase incommodity prices.  Overall, combinedproduct purchases as a percentage of sales of all products decreased to 88% inboth the quarter and six months ended June 30, 2003 from 89% in both of the2002 periods.  The reduction in thispercentage is primarily the result of increases in product prices and anincrease in sales of our equity production.

 

Marketing margins on residue gas averaged$0.06 and $0.08 per Mcf in the second quarter and the six months ended June 30,2003, respectively.  This represents adecrease of approximately $0.02 per Mcf as compared to the margin realizedduring the second quarter and an increase of approximately $0.03 per Mcf as comparedto the margin realized during the six months ended June 30, 2002.  The changes in the marketing margins areprimarily due to transactions associated with our firm transportation capacityfrom the Rocky Mountain region to the mid-continent.  Our firm transportation allows us to purchase gas in the RockyMountain region for resale in the higher priced mid-continent markets.  In the second quarter of 2003, additionaltransportation capacity out of the Rocky Mountain region became operational,which reduced the price difference between the two regions.  We expect that the reduced marginsexperienced in the second quarter of 2003 will continue in future periods.There is no assurance, however, that these margins will continue in the future,that we will be in a similar position to capture them or that we will continueto originate the same amount of transactions in future quarters.

 

Plant and transportation operating expenseincreased by $2.8 million and $5.9 million, respectively, for the three and sixmonths ended June 30, 2003 compared to the same periods in 2002.  These increases were primarily due toincreased throughput at our facilities, additional leased compression in thePowder River Basin coal bed development and higher utility and fuel charges atour plant facilities.  Also contributingto these increases are fees paid to other companies, primarily Rendezvous GasServices, L.L.C., or Rendezvous, for gas gathering services.  Rendezvous is a 50%-owned entity thatdelivers gas to our Granger Complex. Rendezvous is accounted for under the equity method and our share of itsgathering revenues is reflected in Earnings from equity investments.

 

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Oil and gas exploration and productionexpenses increased by $4.1 million and $9.3 million, respectively, for thethree and six months ended June 30, 2003 compared to the same periods in2002.  In our operating areas, thesignificant increase in residue gas prices in 2003 resulted in substantiallyhigher severance tax expenses.  Thisincrease was partially offset by decreased lease operating expenses, or LOE, inthe Powder River Basin coal bed development. Overall, LOE averaged $0.41 per Mcf for the six months ended June 30,2003.  This represents a decrease of$0.04 per Mcf from the same period in 2002. The decrease in LOE is substantially due to increased production volumesin 2003.

 

Depreciation, depletion and amortizationincreased by $442,000 and $639,000, respectively, for the three and six monthsended June 30, 2003 as compared to the same periods in 2002.  These increases were the result ofadditional capital expenditures and depletion on our oil and gas assets, whichwas substantially offset by revisions to the operating lives and salvage valuesof our operating assets.  Theserevisions were the result of analysis performed in connection with the adoptionof SFAS No. 143.

 

Selling and administrative expenses decreasedby $2.0 million for the three months ended June 30, 2003 as compared to thesame period in 2002, due to a reduction in accruals for doubtful accounts.  In thesecond quarter of 2002, we accrued a total of $1.6 million for doubtfulaccounts, primarily due to the bankruptcy filing of a large mid-western co-opin that quarter.  Selling andadministrative expenses remained relatively constant for the six months endedJune 30, 2003 as compared to the same period in 2002 as higher health insurancecosts and higher compensation expenses were substantially offset by a reductionin the accruals for doubtful accounts.

 

In the first six months of 2003, in order toproperly align our hedged volumes of natural gas to our forecasted equityproduction for 2003, we discontinued hedge treatment on financial instrumentsfor 10 MMcf per day of natural gas and 50,000 Barrels per month of ethane.  As a result, a pre-tax loss of $2.8 millionwas reclassified into earnings in the six months ended June 30, 2003 fromAccumulated other comprehensive income.

 

***Cash Flow Information***

 

Cash flows from operatingactivities increased by $73.7 million in the first six months of 2003 comparedto the same period in 2002. This increase was primarily due to an increase innet income in the first six months of 2003 compared to the prior year and thetiming of cash receipts and payables.

 

Cash flows used in investingactivities increased by $12.0 million in the first six months of 2003 comparedto the same period in 2002.  Thisincrease was primarily due to a higher level of capital expenditures.

 

Cash flows used in financingactivities increased by $46.5 million in the first six months of 2003 comparedto the same period in 2002. This increase was due to increased cash flows fromoperating activities, which was used to reduce our long-term debt.

 

***Other Information***

 

***Acquisition of GatheringSystems.*** Effective February 1, 2003, we acquired 18 gathering systems in Wyoming,primarily located in the Green River Basin with smaller operations in thePowder River and Wind River Basins, for a total of $37.1 million.  Several of the systems located in the PowderRiver Basin do not integrate directly into our existing systems, andaccordingly we are negotiating for the sale of these systems.  These systems are classified as Assets heldfor sale on the Consolidated Balance Sheet at June 30, 2003.  During the three and six months ended June30, 2003, the systems included in Assets held for sale generated net losses ofapproximately ($239,000) and ($92,000), respectively, and are immaterial forseparate presentation as a discontinued operation.

 

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***Critical Accounting Policies***

 

Accounting rules generally involve aninterpretation and implementation of existing rules, and the use of judgment,to the specific set of circumstances existing in our business.  We make every effort to properly comply withall applicable rules on or before their adoption, and we believe the properimplementation and consistent application of the accounting rules is critical.  Our critical accounting policies andestimates are discussed below.

 

***Use ofEstimates. ***Thepreparation of consolidated financial statements in conformity with generallyaccepted accounting principles requires us to make estimates and assumptionsthat affect the amounts reported for assets and liabilities, the disclosure ofcontingent assets and liabilities at the date of the financial statements, andthe amounts reported for revenues and expenses during the reportingperiod.  We evaluate these estimates onan ongoing basis, utilizing historical experience, consultation with expertsand other methods we consider reasonable in the particular circumstances.  However, actual results may differsignificantly from the estimates used. Any effects on our business, financial position or results of operationsresulting from revisions to these estimates will be recorded in the period inwhich the facts that necessitate a revision become known.

 

***Property andEquipment. *** 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 providedusing the straight-line method based on the estimated useful life of eachfacility, which ranges from three to 35 years. Useful lives are determined based on the shorter of our estimate of thelife of the equipment or our estimate of the reserves serviced by the equipment.  Among other factors, the estimates considerour experience with similar assets and technical analysis of the reserves.  The cost of acquired gas purchase contractsis amortized using the straight-line method or units of production.  If the actual lives of the equipment or thereserves serviced by the equipment were less than we originally estimated, wemay be required to record a loss upon retirement of a specific asset.

 

In connection with the adoption of SFAS No.143, we completed a review of our operating assets and reevaluated the operatinglife and salvage values of the associated equipment.  As a result of this evaluation, we extended the useful life ofmany of our operating assets and adjusted the estimated salvage value of ouroperating equipment.  These adjustmentsresulted in an approximate $5.8 million, or $0.10 per share of common stock –assuming dilution, decrease in depreciation, depletion and amortization in thesix months ended June 30, 2003 from the expense calculated using the previoususeful lives.  The adjustments to the salvagevalue and depreciable lives of our assets are treated as a revision of anestimate and are accounted for on a prospective basis.

 

***Oil and GasProperties 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-productionmethod based on estimated proved reserves. The unit of production method is sensitive to the determination ofproved reserves.  We utilize technicalanalysis and outside expertise annually to determine the reserves associatedwith our oil and gas properties.   Tothe extent the reserves are modified based on this review, the depletiondetermined under the units of production method will be increased or decreasedon a prospective basis.

 

***Impairment ofLong-Lived Assets.*** If changes in the expected performance of an asset occur, or ifoverall economic conditions warrant, we will review our assets to determinetheir economic viability.  This reviewis completed at the plant facility, the related group of plant facilities orthe oil and gas producing property level. In order to determine whether an impairment exists, we compare the net bookvalue of the asset to the estimated fair market value or the undiscountedexpected future net cash flows, determined by applying future prices estimatedby management over the shorter of the lives of the facilities or the reservessupporting the facilities.  If animpairment exists, write-downs of assets are based upon expected future netcash flows discounted using an interest rate commensurate with the riskassociated with the underlying asset. This analysis is sensitive to, among other things; management’sexpectation of commodity prices, operating costs, drilling plans and productionrates.

 

***Identification ofDerivatives and Mark to Market 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 

 

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meeting the criteria for exclusions fromderivatives 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 a number of risks inherent in the industry in which weoperate, including price volatility, counter party credit risk, the success ofour drilling programs and other gas supply. Our financial condition and results of operations will dependsignificantly upon the prices we receive for gas and NGLs.  These prices are subject to fluctuations inresponse to changes in supply and demand and a variety of additional factorsthat are beyond our control.  Inaddition, we must continually connect new wells to our gathering systems inorder to maintain or increase throughput levels to offset natural declines indedicated volumes.  The number of newwells drilled will depend upon, among other factors, prices for gas and oil,the drilling budgets of third-party producers, the energy policy of the federalgovernment and the availability of foreign oil and gas, none of which are withinour control.

 

***Recently IssuedAccounting 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.  For a more detailed description of thesepronouncements see “Part 1 – Financial Information – Item 1. Financial Statements.”

 

***Liquidity and Capital Resources***

 

Our sources ofliquidity and capital resources historically have been net cash provided byoperating activities, funds available under our financing facilities andproceeds from offerings of debt and equity securities.  In the past, these sources have beensufficient to meet our needs and finance the growth of our business.  We can give no assurance that the historicalsources of liquidity and capital resources will be available for futuredevelopment and acquisition projects, and we may be required to seek additionalor alternative financing sources. Product prices, sales of inventory, the volumes of natural gas processedby our facilities, the volume of natural gas produced from our producingproperties, the margin on third-party product purchased for resale, as well asthe timely collection of our receivables will all affect future net cashprovided by operating activities. Additionally, our future growth will be dependent upon obtainingadditions to dedicated plant reserves, acquisitions, new project development,marketing results, efficient operation of our facilities and our ability toobtain financing at favorable terms.

 

During thepast several years, although some of our plants have experienced declines indedicated reserves, overall we have been successful in connecting additionalreserves to more than offset the natural declines.  The overall level of drilling will depend upon, among otherfactors, the prices for oil and gas, the drilling budgets of third-partyproducers, availability of transportation capacity to market centers, theenergy and environmental policy and regulation by governmental agencies, andthe availability of foreign oil and gas, none of which is within our control.There is no assurance that we will continue to be successful in replacing thededicated reserves processed at our facilities.  Any prolonged reduction in prices for natural gas and NGLs maydepress the levels of exploration, development and production by third-partiesand us.  Lower levels of theseactivities could result in a corresponding decline in the demand for ourgathering, processing and treating services. A reduction in any of these activities could have a material adverseeffect on our financial condition, results of operations and cash flows.

 

We believe thatthe amounts available to be borrowed under the revolving credit facility,together with net cash provided by operating activities, will provide us withsufficient funds to connect new reserves, maintain our existing facilities andcomplete our current capital expenditure program.  Depending on the timing and the amount of our future projects, wemay be required to seek additional sources of capital.  Our ability to secure such capital isrestricted by our financing facilities, although we may request additionalborrowing capacity from our lenders, seek waivers from our lenders to permit usto borrow funds from third-parties, seek replacement financing facilities fromother lenders, use stock as a currency for acquisitions, sell existing assetsor a combination of alternatives.  Whilewe believe that we would be able to secure additional financing, if required,we can provide no assurance that we will be able to do so or as to the terms ofany additional financing.  In July 2003,we utilized a portion of the revolving credit facility to fund a $10.0 millionscheduled payment on the Master Shelf Agreement.  We believe that cash provided by operating activities and amountsavailable under the revolving credit facility will be sufficient to meetremaining scheduled principal repayments during 2003 of $33.3 million under theMaster Shelf Agreement and our preferred stock dividend requirements during theremainder of 2003 of approximately $3.6 million.

 

We haveeffective shelf registration statements filed with the SEC for an aggregate of$200 million of debt securities and preferred stock, along with the shares ofcommon stock, if any, into which those securities are convertible, and $62million of debt securities, preferred stock or common stock.  These shelf registrations allow us to accessthe debt and equity markets without the requirement of further SEC review.

 

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Our sourcesand uses of funds for the six months ended June 30, 2003 are summarized asfollows (dollars in thousands):

 
| **Sources of funds:** |                                                            |   | ** ** |
|-----------------------|-----------------------------------------------------------------|--------|------------|
|                  | Borrowings under the revolving credit facility                  |   | $          | 573,900 |   |
|                  | Borrowings under the Master Shelf Agreement                     |   | 25,000     |   |
|                  | Proceeds  from the dispositions of property and equipment       |   | 3,564      |   |
|                  | Net cash provided by operating activities                       |   | 141,650    |   |
|                  | Proceeds from exercise of common stock options                  |   | 2,618      |   |
|                  | Total sources of funds                                          |   | $          | 746,732 |   |
| **Uses of funds:**    |                                                            |   |       |
|                  | Payments related to long-term debt (including debt issue costs) |   | $          | 627,329 |   |
|                  | Capital expenditures                                            |   | 79,551     |   |
|                  | Preferred dividends paid                                        |   | 3,623      |   |
|                  | Common dividends paid                                           |   | 3,310      |   |
|                  | Total uses of funds                                             |   | $          | 713,813 |   |

 

***Capital Investment Program.***  Our capital expenditures during the sixmonths ended June 30, 2003 totaled approximately $79.6 million.  Overall, capital expenditures during thisperiod consisted of the following: (i) approximately $14.4 million related togathering, processing, treating and pipeline assets, including $3.3 million formaintaining existing facilities; (ii) approximately $22.3 million related toexploration and production and lease acquisition activities; (iii) $37.1million for the acquisition of 18 gathering systems, which closed in January2003; (iv) approximately $3.1 million for information technology and otheritems; and (v) approximately $2.7 million for capitalized overhead andinterest.

 

We currentlyanticipate capital expenditures in 2003 of approximately $210.1 million, anincrease of $27.8 million from our previous 2003 capital budget.  The revised 2003 capital budget consists ofthe following: (i) approximately $83.9 million related to gathering,processing, treating and pipeline assets, including $13.3 million formaintaining existing facilities; (ii) approximately $77.0 million related toexploration 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 28% and 51%, respectively, of the total 2003 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.

 

***Contractual Commitments and Obligations***

 

***Contractual Cash Obligations.***  A summary of our contractual cashobligations as of June 30, 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              |   | $                     | 5,928   |                    | $      | 382 |   | $ | 1,669 |   | $ | 1,931 |   | $ | 1,946 |   |
| Operating Leases                                       |   | 77,057                |    | 8,546                   |   | 23,472 |   | 22,453 |   | 22,586 |   |
| Firm Transportation Capacity and Gathering  Agreements |   | 229,199               |    | 16,263                  |   | 55,587 |   | 54,493 |   | 102,856 |   |
| Firm Storage Capacity Agreements                       |   | 14,967                |    | 3,055                   |   | 6,610 |   | 3,379 |   | 1,923 |   |
| Long-term Debt                                         |   | 333,333               |    | 43,333                  |   | 45,000 |   | 65,000 |   | 180,000 |   |
| Total Contractual Cash Obligations                     |   | $                     | 660,484 |                    | $      | 71,579 |   | $ | 132,338 |   | $ | 147,256 |   | $ | 309,311 |   |

 

***Guarantee of FortUnion Project Financing.***   We own a 13% equity interest in the Fort Union Gas Gathering,L.L.C., or Fort Union, and are the construction manager and fieldoperator.  Fort Union gathers and treatsnatural gas in the Powder River Basin in northeast Wyoming.  Initial construction and any expansions ofthe gathering header and treating system have been project financed by FortUnion.  This debt is amortizing on anannual basis and is scheduled to be fully paid in 2009.  All participants in Fort Union haveguaranteed Fort Union’s payment of the project financing on a proportional

 

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basis, resulting in ourguarantee of $5.9 million of the debt of Fort Union at June 30, 2003.  Our requirement to fund under this guaranteewould be reduced by the value of assets held by Fort Union.  This guarantee is not reflected on ourConsolidated Balance Sheet.

 

***OperatingLeases. ***Inthe ordinary course of our business operations, we enter into operating leasesfor office space, office equipment, communication equipment and transportationequipment.  In addition, we have enteredinto operating leases for compression equipment.   Payments made on these leases are a component of operatingexpenses and are reflected on the Consolidated Statement of Operations and, asoperating leases, are not reflected on our Consolidated Balance Sheet.  These leases have terms ranging from onemonth to ten years with return or fair market purchase options available atvarious times during the lease.   If wewere to exercise the early buyout options on all the leased equipment, thesepurchase options would require the capital expenditure of approximately $33.9million between 2007 and 2012.

 

***Firm TransportationCapacity and Gathering Agreements.***  Access to firm transportation is alsoa significant element of our business strategy.  Firm transportation ensures that our equity production has accessto downstream markets and allows us to capture incremental profit when pricingdifferentials between physical locations occur.  As of June 30, 2003, we had contracts for approximately 616 MMcfper day of firm transportation.  Thisamount represents our 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 per day of firm capacity on threeseparate pipelines.   The total rateunder these long-term contracts to transport this gas to the Mid-Continentapproximates $0.35 per Mcf.  Ourremaining firm capacity consists of 103 MMcf per day to markets within theRocky Mountains and 137 MMcf per day contracted in various other marketsthroughout the country.  In addition, wehold 83 MMcf per day of firm gathering capacity on the Fort Union gatheringline.

 

A portion ofthis firm transportation capacity was contracted for use in our Marketingoperations.  For example, our Marketingsegment purchases gas in the Rocky Mountain region, transports this gasutilizing its 56 MMcf per day of our firm transportation capacity to theMid-Continent, and resells the gas to various markets.  During the six months ended June 30, 2003,these types of transactions have been profitable as the price difference, orbasis, between the Rocky Mountain and Mid-Continent regions has exceeded thecost of transportation. We expect that the fixed fees associated with ourcontracts for firm transportation capacity during the remainder of 2003 willaverage approximately $0.13 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 customarilystore gas in underground storage facilities to ensure an adequate supply forlong-term sales contracts and to capture seasonal price differentials.  As of June 30, 2003, we had contracts inplace for approximately 13.3 Bcf of storage capacity at various third-partyfacilities.  Of the total storagecapacity under contract, approximately 5.2 Bcf is under contract to ourCanadian subsidiary, WGR – Canada, Inc. and Western guarantees the subsidiary’sperformance under these contracts.  Thissubsidiary is wholly owned by us and fully consolidated in our financialstatements.

 

The feesassociated with these contracts during the remainder of 2003 will average $0.39per Mcf of annual capacity.  Theassociated contract periods at June 30, 2003 have an average term oftwenty-four months.  At June 30, 2003,we held gas in our contracted storage facilities and in imbalances ofapproximately 12.9 Bcf at an average cost of $4.47 per Mcf compared to 16.3 Bcfat an average cost of $2.50 per Mcf at June 30, 2002.  These positions are for storage withdrawals within the nexttwelve months.  At the time that weplace product into storage, we contract for the sale of that product,physically or financially, and do not speculate on the future value of theproduct.

 

From time totime, we lease NGL storage space at major trading locations to facilitate thedistribution of products. At June 30, 2003, we held NGLs in storage at variousthird-party facilities of 2,662 MGal, consisting primarily of propane andnormal butane, at an average cost of $0.25 per gallon compared to 3,933 MGal atan average cost of $0.30 per gallon at June 30, 2002.

 

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***Long-term Debt***

 

***Revolving*Credit*Facility. ***At June 30,2003, $45.0 million was outstanding under our existing four-year, $300 millionrevolving credit facility.  Loans madeunder this facility are secured by a pledge of the capital stock of oursignificant subsidiaries.  Thesesubsidiaries also guarantee the borrowings under the facility.  The facility contains a provision thatrequires us to secure loans under the facility with 75% of our oil and gasreserves.  This provision would only betriggered in the event of a reduction to a debt rating on the revolving creditfacility of Ba3 or lower by Moody’s Investors Service, Inc., or Moody’s, or thereduction to a debt rating on the revolving credit facility of BB- or lower byStandard & Poor’s Rating Services, a division of The McGraw-Hill Companies,Inc., or S&P.  In August 2003,Moody’s issued a rating of Ba1 and S&P issued a rating of BB+ on therevolving credit facility.

 

The borrowingsunder the credit facility bear interest at Eurodollar rates or a base rate, asrequested by us, plus an applicable percentage based on our debt tocapitalization ratio.  The base rate isthe agent’s published prime rate.  Wealso pay a quarterly facility fee ranging between 0.30% and 0.50%, depending onour debt to capitalization ratio.  Thisfee is paid on the total commitment.  AtJune 30, 2003, the interest rate payable on borrowings under the new facilitywas approximately 3.04%.

 

Under thecredit facility, we are subject to a number of covenants, including: maintaininga total debt to capitalization ratio of not more than 55%; maintaining a seniordebt to capitalization ratio of not more than 40%; and maintaining an EBITDA tointerest and dividends on preferred stock over the last four quarters in excessof 3.25 to 1.0, increasing to 4.25 to 1.0 by March 31, 2005.

 

The creditfacility ranks equally with borrowings under our Master Shelf Agreement withThe Prudential Insurance Company.

 

***Master ShelfAgreement. ***Amountsoutstanding under the Master Shelf Agreement with The Prudential InsuranceCompany of America at June 30, 2003 are as indicated in 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 borrowingsunder the Master Shelf Agreement are secured by a pledge of the capital stockof our significant subsidiaries, some of which have also provided a guaranty ofpayments owed by us under the facility.  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 a reduction to the debtrating on the revolving credit facility of Ba3 or lower by Moody’s or thereduction to the debt rating on the revolving credit facility of BB- or lowerby S&P.  In August 2003, Moody’sissued a rating of Ba1 and S&P issued a rating of BB+ on the revolvingcredit facility.

 

Under ourMaster Shelf Agreement, we are subject to a number of covenants, including:maintaining a minimum tangible net worth equal to the sum of $300 million plus50% of consolidated net earnings earned from January 1, 1999 plus 75% of thenet proceeds of any equity offerings after January 1, 1999; maintaining a totaldebt to capitalization ratio of not more than 55% and a senior debt tocapitalization ratio of not more than 40%; maintaining a quarterly test ofEBITDA to interest for the last four quarters in excess of 3.25 to 1.0,increasing to 4.25 to 1.0 by March 31, 2005; and maintaining a ratio of seniordebt to EBITDA of no greater than 4.0 to 1.0.

 

In July 2003,we utilized funds available under the revolving credit facility to fund a $10.0million scheduled payment under the Master Shelf Agreement.  In the remainder of 2003, we will makerequired principal repayments under the Master Shelf Agreement totaling $33.3million.  We intend to fund theserepayments with funds available under the revolving credit facility.

 

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***Senior SubordinatedNotes. ***In1999, we sold $155.0 million of Senior Subordinated Notes in a privateplacement with a final maturity of 2009 due in a single payment which weresubsequently exchanged for registered publicly tradable notes under the sameterms and conditions.  The SubordinatedNotes bear interest at 10% per annum and were priced at 99.225% to yield10.125%.  These notes contain covenants,which include limitations on debt incurrence, restricted payments, liens andsales of assets.  The Subordinated Notesare unsecured and are guaranteed on a subordinated basis by our materialsubsidiaries.  We incurred approximately$5.0 million in offering commissions and expenses, which were capitalized andare being amortized over the term of the notes.

*** ***

***CovenantCompliance. ***Wewere in compliance with all covenants in our debt agreements at June 30, 2003.

 

***Upstream Operations***

 

A vital aspectof our long-term business plan is to double proven reserves and equityproduction of natural gas from the level at December 31, 2001 over a three tofive year period.  In order to achievethis goal, we will focus on continued development of our leasehold positions inthe Powder River Basin coal bed methane project and the Greater Green RiverBasin projects.  Each of our existingupstream projects are fully integrated with our midstream operations. In otherwords, we provide the gathering, compression, processing, marketing ortransportation services for both our own production and for third-partyoperators.  Additionally, we areactively pursuing new exploration development and producing property acquisitionopportunities.

 

***PowderRiver Basin Coal Bed Methane. ***Wecontinue to develop our Powder River Basin coal bed methane reserves and expandthe associated gathering system in northeast Wyoming.  The Powder River Basin coal bed methane area is currently one ofthe largest on-shore plays for the development of natural gas in the UnitedStates.  Within this area, together withour co-developer, in the first six 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 June 30,2003, we held the drilling rights on approximately 529,000 net acres in thisbasin, and as of December 31, 2002, we had established proven developed andundeveloped reserves totaling 414 Bcfe on a portion of this acreage, 52% ofwhich are proven and developed.  Thedrilling operations in the Powder River Basin through June 30, 2003 haveprimarily focused on developing reserves in the Wyodak coal, which is locatedon the east side of the coal bed development. We participated in the drilling of 273 gross wells through the firstseven months of 2003.  The averagedrilling and completion cost for our coal bed methane gas wells hasapproximated $90,000 to $120,000 per well, with average reserves per successfulWyodak well of approximately 275 MMcf. The majority of future development will be concentrated on developingthe Big George and other coal seams. Much of the Big George coal seam is deeper and thicker than the Wyodakcoal.  We expect that as wells aredrilled and developed in the Big George coal, the gas reserves and productionper well and the average drilling and completion cost per well will increase.

 

We currentlyplan to participate in a total of 600 to 650 gross wells in 2003, which is areduction from our original estimate of 845 wells.  The reduction is the result of delays in receiving permits todrill on federal lands from the Bureau of Land Management, or BLM.  Our share of production from wells in whichwe own an interest averaged approximately 109 MMcfe per day in the first sixmonths of 2002 and increased to an average of approximately 122 MMcfe per dayin the first six months of 2003.  Wecurrently anticipate production to remain relatively constant at this ratethrough the end of 2003, assuming that the issuance of permits on federalleases as a result of the Environmental Impact Statement, or EIS, as describedbelow, are not further delayed.

 

Industry-wide,production from the Big George coal increased to approximately 99 MMcf per dayin May 2003 from nine separate areas. This represents an increase of 212% since June 2002.  We are currently evaluating 11 pilot areasand one development area in the Big George. We have marketable production quantities in the All Night Creek,Pleasantville and Kingsbury areas.  InJuly 2003, these areas were producing a combined 32 gross MMcf per day, a 208%increase since June 2002.  At December 31,2002, we had proven reserves of 49 Bcfe in the Big George coal, primarily associatedwith the All Night Creek development area.

 

On April 30,2003, the BLM issued the final Record of Decision, or ROD, in relation to itsEIS regarding future Coal Bed Methane, or CBM, drilling in the Powder RiverBasin.  The ROD requires additional surveysfor plant and animal species, cultural surveys and noxious weedmitigation.  We have filed permitapplications for approval by the BLM under the terms of the new EIS, but areunable to predict the rate at which permits will be granted. This timing mayalso be affected by several lawsuits, which were filed on May 1, 2003 in theU.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 thelitigation or the impact, if any, on the timing of our development. For furtherinformation, see "Part II—Other Information—Item1. Legal Proceedings"of this Form 10-Q.

 

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Additionally,the Wyoming Department of Environmental Quality, or DEQ, has revised somestandards for surface water discharge that have allowed the issuance of most ofthe permits that apply to the Cheyenne and Belle Fourche drainage areas. Themajority of our existing production is from wells draining into theseareas.  Most of our undevelopedprospects from the Big George formation are located in the Powder Riverdrainage area.  The Wyoming DEQ willrequire additional water management techniques, such as containment or treating,in these areas pursuant to the conditions described in the EIS referred toabove.  While we believe theseadditional requirements will add to the cost of development of this area we donot believe they will have a significant impact on our results of operation orfinancial position.

 

Our 2003capital budget in the Powder River Basin coal bed project includesapproximately $45.2 million for drilling costs, production equipment and leaseacquisitions, of which approximately $18.2 million was spent in the first sixmonths of 2003.  Depending upon futuredrilling success, we may need to make additional capital expenditures orleasing commitments to continue expansion in this basin.  In addition, due to regulatoryuncertainties, which are beyond our control, we can make no assurance that wewill incur this level of capital expenditure during 2003.

 

***GreaterGreen River Basin.* **Our upstream assets in the Green River Basin of southwestWyoming are located in the Jonah Field and Pinedale Anticline areas.  As of June 30, 2003, we owned approximately194,000 gross oil and gas leasehold acres, or approximately 33,000 net acres,in these areas.  During the first sixmonths of 2003, we participated in 16 gross wells, or two net wells, in theseareas, at a cost of $2.4 million and experienced a success rate of 100%.  Our capital budget for 2003 in the JonahField and Pinedale Anticline areas provides for expenditures of approximately$20.1 million for drilling costs and production equipment.  Due to drilling and regulatory uncertainties,which are beyond our control, there can be no assurance that we will incur thislevel of capital expenditure.  Duringthe remainder of 2003, we expect to participate in the drilling of 29 grosswells, or approximately three net wells on the Pinedale Anticline.  The expected gross costs to drill asuccessful well in this area range from approximately $3.5 million to $5.0million, depending on location of the well site and the depth of the well.  Average well depths in this area range fromapproximately 13,000 feet to 14,200 feet and average gross reserves persuccessful well approximate 6 to 8 Bcfe. During the second quarter of 2003, we produced an average of 27 MMcfeper day, net, from these areas.  We hadestablished proven developed and undeveloped reserves totaling 161 Bcfe atDecember 31, 2002.  There can be noassurance, however, as to the ultimate recovery of these reserves.

 

We continue to explore and develop our acreage position in the SandWash Basin in northwest Colorado, located in the Greater Green RiverBasin.   We own approximately 208,000gross oil and gas leasehold acres, or approximately 177,000 net acres, in thisbasin.  The majority of this acreage isin the exploration phase and will be evaluated in 2003 and subsequent years.  Our capital budget in this area provides forexpenditures of approximately $5.3 million during 2003 for our participation inthe drilling of six gross developmental wells, or four net wells, and threeworkovers of existing wells.  Of thetotal 2003 capital budget, approximately $1.4 million was spent in the firstsix months of 2003.   

 

***Exploration. ***We are also actively seeking to add anothercore project that is focused on Rocky Mountain natural gas.  We have acquired a substantial acreageposition in one new area and will continue to evaluate the potential of thisarea.  We will utilize our expertise inexploration and low-risk development of tight-gas sands, coal bed methane andfractured shale plays to evaluate acquisitions of either additional leaseholds,proven and undeveloped reserves or companies with operations focused in thisarea.  

 

 

***Midstream Operations***

 

Our midstreamoperations consist of our gathering, processing, treating, marketing andtransportation operations.  An importantelement of our long-term business plan is to meet or exceed throughputprojections in these areas and to optimize their profitability.  To achieve this goal, we must continue ourefforts to add to natural gas throughput levels through new well connectionsand through the expansion or acquisition of gathering or processingsystems.  We also seek to increase theefficiency of our operations by modernization of equipment and theconsolidation of existing facilities.

 

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

 

At June 30, 2003,we operated a total of 20 significant gathering, processing and treatingfacilities, or plant operations, with approximately 9,925 miles of gatheringlines.  These facilities are primarilylocated in five states and have a combined throughput capacity of 2.9 billioncubic feet, Bcf, per day of natural gas. Our operations are located in some of the most actively drilled oil and gasproducing basins in the United States.  Fiveof our processing plants can further separate, or fractionate, the mixed NGL streaminto ethane, propane, normal butane and natural gasoline to obtain a highervalue for the NGLs, and three of our plants are capable of processing andtreating natural gas containing hydrogen sulfide or other impurities thatrequire removal prior to delivery to market pipelines.  In addition to our integrated upstream andmidstream operations in the Powder River and Green River Basins in Wyoming, 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.

 

***Powder River Basin***.Our midstream operations in the Powder River Basin are fully integrated withour upstream operations as we provide the gathering, compression and processingservices for our own production. Additionally we provide the same types of services forthird-parties.  As of June 30, 2003, ourassets in the Powder River Basin in northeast Wyoming were primarily comprisedof our coal bed methane gathering system with a capacity of 525 MMcf per day,our 13% equity interest in Fort Union and several gas processing facilitieswith a combined capacity of 146 MMCF per day.

 

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We averaged414 MMcf per day of CBM gathering volumes, including third-party gas, duringthe second quarter of 2003. This represents a 15 percent increase compared tothe same period in 2002.  Of thatvolume, approximately 107 MMcf per day was transported through our MIGCpipeline.

 

We are the construction manager and field operator of the Fort Uniongathering system and header.  The FortUnion system delivers coal bed methane gas to a treating facility nearGlenrock, Wyoming and accesses interstate pipelines serving gas markets in theRocky Mountain and Midwest regions of the United States.  The gathering pipeline has a capacity of 635MMcf per day.  We have a long-term, firmgathering agreement with Fort Union for 83 MMcf per day of this capacity at$0.14 per Mcf.

 

Our capitalbudget in the Powder River Basin for midstream activities provides forexpenditures of approximately $15.2 million during 2003, of which approximately$5.5 million was spent in the first half of the year.  Depending upon our future drilling success, we may need to makeadditional capital expenditures or leasing commitments to continue expansion inthis basin.  Due to drilling,regulatory, commodity pricing and other uncertainties, which are beyond ourcontrol, there can be no assurance that we will incur this level of capitalexpenditure.

 

***GreenRiver Basin***.  Our midstream operations in the Green RiverBasin of southwest Wyoming are also fully integrated with our upstreamoperations in this area.  Our midstreamassets in this basin are comprised of the Granger and Lincoln Roadfacilities, or collectively the Granger complex, our 50% equity interest inRendezvous, our Red Desert facility and our recently acquired Table Rock,Wamsutter and Desert Springs gathering systems.  These facilities have a combined gathering capacity of 682 MMcfper day, and in the six months ended June 30, 2003, these facilities averagedthroughput of 543 MMcf per day.  Additionally, these systems have a combined processing capacity of 327MMcf per day and in the six months ended June 30, 2003, processed an average of215 MMcf per day.

 

Our 2003capital budget for midstream activities in this basin provides for expendituresof approximately $81.3 million during 2003 of which $38.9 million was spent inthe first half of the year.  Thiscapital budget includes approximately $28.1 million for gathering lines andinstallation of compression to expand the capacity of our Granger Complex , ourWamsutter gathering system and our Red Desert facility, $16.1 million foradditional contributions to Rendezvous for the expansion of its system and$37.1 million for the acquisition of additional gathering systems in February2003.   Due to drilling, commoditypricing and regulatory uncertainties, which are beyond our control, there canbe no assurance that we will incur this level of capital expenditure.

 

In 2001, we, together with an unrelated third-party, formedRendezvous.  Rendezvous gathers gasalong the Pinedale Anticline for blending or processing at either our GrangerComplex 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 in June 2003 was gathering216 MMcf per day.   An expansion of thesystem is scheduled to be completed in the fourth quarter of 2003.  The expansion would extend the systemapproximately 24 miles further into the Pinedale Anticline as well as increasethe capacity of the system to 350 MMcf per day at an estimated cost of $32.0million gross, of which our share is approximately $16.0 million.  As part of our expansion process, we areimplementing a 100 MMcf per day processing capacity upgrade at our Grangerplant at a cost of $1.0 million.

 

***West Texas******.* **Ourprimary assets in west Texas are the Midkiff/Benedum complex and the Gomez andMitchell Puckett treating facility. These facilities process gas produced by third-parties in the PermianBasin, have a combined operational capacity of 565 MMcf per day and processedan average of 283 MMcf per day in the first half of 2003.  Also for this period, these facilitiesproduced an average of 205 MMcf per day of natural gas for delivery to salesmarkets and produced an average of 777 MGal per day of NGLs.  Our capital budget in this area provides forexpenditures of approximately $7.4 million during 2003, of which $2.1 millionwas spent in the first six months.

 

***Oklahoma******.* **Ourprimary assets in Oklahoma are the Chaney Dell and Westana systems.  These facilities gather and process gasproduced by third-parties in the Anadarko Basin and have a combined operationalcapacity of 175 MMcf per day.  In thesix months ended June 30, 2003, these facilities processed an average of 156MMcf per day, produced an average of 137 MMcf per day of natural gas fordelivery to sales markets and produced 306 MGal per day of NGLs.  Our capital budget in this area provides forexpenditures of approximately $15.7 million during 2003, of which approximately$4.5 million has been spent in the first six months.

 

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***PrincipalFacilities.*** The following tables provide information concerning our principalgathering, processing and treating facilities and transportation assets at June30, 2003.

 
| **Facilities (1)**                |   | **Year  Placed  In Service**      | ** ** | **Gas  Gathering  System  Miles (2)** |   | **Gas  Throughput  Capacity  (MMcf/D) (3)** |   | **Average  for the Six Months Ended  June 30, 2003** |   |
|-----------------------------------|--------|-----------------------------------|------------|---------------------------------------|--------|---------------------------------------------|--------|------------------------------------------------------|--------|
| **Gas  Throughput  (MMcf/D) (4)** |   | **Gas  Production  (MMcf/D) (5)** |       | **NGL  Production  (MGal/D) (5)**     |
| Texas                             |   |                              |       |                                  |   |                                        |   |                                                 |   |   |   |   |   |
| Gomez Treating (6)                |   | 1971                              |       | 386                                   |   | 280                                         |   | 85                                                   |   | 77 |   | — |   |
| Midkiff/Benedum                   |   | 1949                              |       | 2,243                                 |   | 165                                         |   | 134                                                  |   | 88 |   | 776 |   |
| Mitchell Puckett Treating (6)     |   | 1972                              |       | 93                                    |   | 120                                         |   | 64                                                   |   | 40 |   | 1 |   |
| Wyoming                           |   |                              |       |                                  |   |                                        |   |                                                 |   |   |   |   |   |
| Coal Bed Methane Gathering        |   | 1990                              |       | 1,310                                 |   | 525                                         |   | 413                                                  |   | 217 |   | — |   |
| Desert Springs Gathering (13)     |   | 1979                              |       | 65                                    |   | 10                                          |   | 5                                                    |   | 5 |   | 12 |   |
| Fort Union Gas Gathering          |   | 1999                              |       | 167                                   |   | 635                                         |   | 481                                                  |   | 481 |   | — |   |
| Granger (7)(8)(9)                 |   | 1987                              |       | 538                                   |   | 235                                         |   | 228                                                  |   | 148 |   | 350 |   |
| Hilight Complex (7)               |   | 1969                              |       | 626                                   |   | 124                                         |   | 15                                                   |   | 10 |   | 50 |   |
| Kitty/Amos Draw (7)               |   | 1969                              |       | 314                                   |   | 17                                          |   | 6                                                    |   | 4 |   | 26 |   |
| Lincoln Road (9)                  |   | 1988                              |       | 149                                   |   | 50                                          |   | 34                                                   |   | 11 |   | 5 |   |
| Newcastle (7)                     |   | 1981                              |       | 146                                   |   | 5                                           |   | 3                                                    |   | 2 |   | 20 |   |
| Red Desert (7)                    |   | 1979                              |       | 111                                   |   | 42                                          |   | 12                                                   |   | 11 |   | 21 |   |
| Rendezvous                        |   | 2001                              |       | —                                |   | 275                                         |   | 215                                                  |   | 215 |   | — |   |
| Reno Junction (8)                 |   | 1991                              |       | —                                |   | —                                      |   | —                                               |   | - |   | 103 |   |
| Table Rock Gathering (13)         |   | 1979                              |       | 101                                   |   | 20                                          |   | 14                                                   |   | 14 |   | — |   |
| Wamsutter Gathering (13)          |   | 1979                              |       | 186                                   |   | 50                                          |   | 35                                                   |   | 34 |   | 8 |   |
| Wind River Gathering (13)         |   | 1979                              |       | 109                                   |   | 80                                          |   | 43                                                   |   | 43 |   | — |   |
| Oklahoma                          |   |                              |       |                                  |   |                                        |   |                                                 |   |   |   |   |   |
| Chaney Dell/Westana               |   | 1966                              |       | 3,137                                 |   | 175                                         |   | 156                                                  |   | 137 |   | 306 |   |
| New Mexico                        |   |                              |       |                                  |   |                                        |   |                                                 |   |   |   |   |   |
| San Juan River (6)                |   | 1955                              |       | 140                                   |   | 60                                          |   | 30                                                   |   | 24 |   | 47 |   |
| Utah                              |   |                              |       |                                  |   |                                        |   |                                                 |   |   |   |   |   |
| Four Corners Gathering            |   | 1988                              |       | 104                                   |   | 15                                          |   | 3                                                    |   | 2 |   | 17 |   |
| Total                             |   |                              |       | 9,925                                 |   | 2,883                                       |   | 1,976                                                |   | 1,563 |   | 1,742 |   |

 
|                              |   |                         |   |                         |   | **Average  for the Six Months Ended  June 30, 2003** |   |
|-----------------------------------|--------|------------------------------|--------|------------------------------|--------|------------------------------------------------------|--------|
| **Transportation Facilities (1)** |   | **Year  Placed  In Service** |   | **Transportation  Miles(2)** |   | **Pipeline  Capacity  (MMcf/D)(2)**                  |   | **Gas  Throughput  (MMcf/D)(4)** |   |
| MIGC (10)(12)                     |   | 1970                         |   | 245                          |   | 130                                                  |   | 165 |   |
| MGTC (11)                         |   | 1963                         |   | 252                          |   | 18                                                   |   | 10 |   |
| Total                             |   |                         |   | 497                          |   | 148                                                  |   | 175 |   |

 

Footnotes on following page.

 

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(1)                      Our interest in all facilities is100% except for Midkiff/Benedum (73%); Newcastle (50%); Fort Union gatheringsystem (13%) and Rendezvous (50%).  Weoperate all facilities, and all data include our interests and the interests ofother joint interest owners and producers of gas volumes dedicated to thefacility.  Unless otherwise indicated,all facilities shown in the table are gathering, processing or treatingfacilities.

(2)                      Gas gathering system miles,transportation miles and pipeline capacity are as of June 30, 2003.

(3)                      Gas throughput capacity is as ofJune 30, 2003 and represents capacity in accordance with design specificationsunless other constraints exist, including permitting or field compressionlimits.

(4)                      Aggregate wellhead natural gasvolumes collected by a gathering system or volumes transported by a pipeline.

(5)                      Volumes of gas and NGLs areallocated to a facility when a well is connected to that facility; volumesexclude NGLs fractionated for third-parties.

(6)                      Sour gas facility (capable ofprocessing or treating gas containing hydrogen sulfide and/or carbon dioxide).

(7)                      Processing facility that includesfractionation (capable of fractionating raw NGLs into end-use products).

(8)                      NGL production includesconversion of third-party feedstock to iso-butane.

(9)                      Lincoln Road is operated on anintermittent basis to process excess gas from the Granger system.

(10)                MIGC is an interstate pipeline locatedin Wyoming and is regulated by the Federal Energy Regulatory Commission.

(11)                MGTC is a public utility located inWyoming and is regulated by the Wyoming Public Service Commission.

(12)                Pipeline capacity representscertificated capacity at the Powder River junction only and does not includeinterruptible capacity or capacity at other delivery points.

(13)                These facilities were acquired onFebruary 1, 2003.

 

***Transportation. ***We own andoperate MIGC, Inc. an interstate pipeline located in the Powder River Basin inWyoming, and MGTC, Inc. an intrastate pipeline located in northeastWyoming.  MIGC charges a Federal EnergyRegulatory Commission, or FERC, approved tariff and is connected to pipelinesowned by Colorado Interstate Gas Company, Williston Basin Interstate PipelineCompany, Kinder Morgan Interstate Pipeline Co., Wyoming Interstate Company,Ltd. and MGTC.  During the six monthsended June 30, 2003, MIGC transported an average of 165 MMcf per day.  It is anticipated that MIGC will continue tooperate around that level through the remainder of 2003.  MIGC earns fees on a monthly basis from firmcapacity contracts under which the shipper pays for transport capacity whetheror not the capacity is used and from interruptible contracts where a fee ischarged 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 per Mcfin the first six months of 2003.

 

The FERC hasimplemented changes over the past several years to restrict transactionsbetween regulated pipelines and affiliated companies.  In addition, the FERC has proposed to limit the use ofaffiliates’ employees in the operation of regulated entities.  We can make no assurances as to the ultimateregulations passed by the FERC or the effects such regulations may have on theoperating costs of MIGC or our financial position.

 

MGTC providestransportation and gas sales to the Wyoming cities of Gillette, Moorcroft andWright at rates that are subject to the approval of the Wyoming Public ServiceCommission.  During the six months endedJune 30, 2003, MGTC transported an average of 10 MMcf per day.

 

***Marketing.***

 

***Gas*.*  ***Wemarket gas produced at our wells and our plants and purchased fromthird-parties to end-users, local distribution companies, or LDCs, pipelinesand other marketing companies throughout the United States and Canada.  In addition to our offices in Denver, wehave marketing offices in Houston, Texas and Calgary, Alberta.  Third-party sales, firm transportationcapacity on interstate pipelines and our gas storage positions, combined withthe stable supply of gas from our facilities and production, enable us torespond quickly to changing market conditions and to take advantage of seasonalprice variations and peak demand periods. For the six months ended June 30, 2003, our total gas sales volumesaveraged 1.4 Bcf per day, of which 470 MMcf per day was produced at our plantsor from our producing properties.

 

One of theprimary goals of our gas marketing operations continues to be the preservationand enhancement of the value received for our equity volumes of naturalgas.  This goal is achieved through theuse of hedges on the production of our equity natural gas and through the useof firm transportation capacity. Historically, the Rocky Mountain region has traded at a substantialdiscount to the mid-continent and west coast areas as a result of limitedpipeline capacity from the region.  Inthe six months ended June 30, 2003, as a result of our firm transportationcapacity, we realized an approximate $0.57 per Mcf improvement in price fornatural gas relative to the price that would have been received if thesecapacity rights had not existed.  In thesecond quarter of 2003, additional pipeline capacity out of the Rocky Mountainregion went into service.  This pipelineexpansion contributed to a reduction in the price difference between the RockyMountain region and mid-continent market center to approximately $0.62 per Mcfin June

 

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2003 as compared to an averageof $2.30 per Mcf in the first quarter of 2003. We expect this additional pipeline capacity to continue to an ongoingimpact on the price difference between the Rocky Mountain and Mid-Continentregions.  The remainder of our equityproduction of natural gas in the Rocky Mountain region that is not transportedto the mid-continent is hedged for the remainder of 2003 using financialinstruments.

 

We sell gasunder agreements with varying terms and conditions in order to match seasonaland other changes in demand. As of June 30, 2003, the average duration of oursales contracts was 14 months.  The marketingof products purchased from third-parties typically results in low profitmargins relative to the sales price.  Ingeneral, due to price volatility and credit concerns in the energy industry,our overall sales volumes in 2003 may decrease as compared to prior years.

 

Gains andlosses on any accompanying financial transactions are recorded net.  Additionally, for our marketing activities,we utilize mark-to-market accounting. Under mark-to-market accounting, the expected margin to be realized overthe term of the transaction is recorded in the month of origination.  To the extent that a transaction is notfully hedged or there is any hedge ineffectiveness, additional gains or lossesassociated with the transaction may be reported in future periods.

 

***NGLs*.*  ***Wemarket NGLs, or ethane, propane, iso-butane, normal butane, natural gasolineand condensate, produced at our plants and purchased from third-parties, in theRocky 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 ofproduction.  For the six months endedJune 30, 2003, NGL sales averaged 1,640 MGal per day, of which 1,375 MGal perday was produced at our plants.

 

Consumers ofNGLs are primarily the petrochemical industry, the petroleum refining industryand the retail and industrial fuel markets. As an example, the petrochemical industry uses ethane, propane, normalbutane and natural gasoline as feedstocks in the production of ethylene, whichis used in the production of various plastics products.  Over the last several years, thepetrochemical industry has increased its use of NGLs as a major feedstock andis projected to continue to increase such usage.  Further, consumers use propane for home heating, transportationand agricultural applications.  Price,seasonality and the economy primarily affect the demand for NGLs.  As in the case of natural gas, wecontinually monitor and review the credit exposure to our NGL marketingcounterparties.

 

We sell NGLsunder agreements with varying terms and conditions in order to match seasonaland other changes in demand. At June 30, 2003, the terms of our sales contractsrange from one month to five years.  Themarketing of products purchased from third-parties typically results in lowprofit margins relative to the sales price.

 

Gains andlosses on any accompanying financial transactions are recorded net.  Additionally, for our marketing activities,we utilize mark-to-market accounting. Under mark-to-market accounting, the expected margin to be realized overthe term of the transaction is recorded in the month of origination.  To the extent that a transaction is notfully hedged or there is any hedge ineffectiveness, additional gains or lossesassociated with the transaction may be reported in future periods.

 

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

 

Our commodityprice risk management program has two primary objectives.  The first goal is to preserve and enhancethe value of our equity volumes of gas and NGLs with regard to the impact ofcommodity price movements on cash flow and net income in relation to thoseanticipated by our operating budget. The second goal is to manage price risk related to our marketingactivities to protect profit margins. This risk relates to fixed price purchase and sale commitments, thevalue of storage inventories and exposure to physical market price volatility.

 

We utilize acombination of fixed price forward contracts, exchange-traded futures andoptions, as well as fixed index swaps, basis swaps and options traded in theover-the-counter, or OTC, market to accomplish these goals.  These instruments allow us to preserve valueand protect margins because corresponding losses or gains in the value of thefinancial instruments offset gains or losses in the physical market.

 

We also usefinancial instruments to reduce 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 intofutures transactions on the New York Mercantile Exchange, or NYMEX, and throughOTC swaps and options with various counterparties, consisting primarily ofinvestment banks, financial institutions and other natural gas companies.  We conduct credit reviews of all of our OTCcounterparties and have agreements with many of these parties that containcollateral requirements.  We generallyuse standardized swap agreements that allow for offset of positive and negativeOTC exposures.  OTC exposure ismarked-to-market daily for the credit review process.  Our exposure to OTC credit risk is reduced by our ability torequire a margin deposit from our counterparties based upon the mark-to-marketvalue of their net exposure.  We arealso subject to margin deposit requirements under these same agreements andunder margin deposit requirements for our NYMEX transactions.  Primarily as a result of our equity hedgepositions for natural gas and liquid products, we have posted margin totaling$3.0 million with various counterparties at July 31, 2003.

 

We continuallymonitor and review the credit exposure to our marketing counterparties.  Additionally, beginning in 2001, we becameincreasingly concerned with our credit exposure to our customers, primarily acategory of our customers generally known as “energy merchants.”  Energy merchants create liquidity in themarketplace for natural gas transactions and have historically been some of ourlargest suppliers and customers.  Inorder to minimize our credit exposures, we have utilized existing nettingagreements to reduce our net credit exposure, established new netting agreementswith additional customers, terminated several long-term marketing obligations,negotiated accelerated payment terms with several customers, and reduced theamount of credit which we make available to various customers.  Although netting agreements similar to thosethat we utilize have been upheld by bankruptcy courts in the past, if any ofthese customers with whom we have netting agreements were to file forbankruptcy, we can provide no assurance that our agreements will not bechallenged or as to the outcome of any challenge.

 

In July 2003,one of our marketing counterparties filed a petition for bankruptcy protectionunder Chapter 11 of the U.S. Bankruptcy code. As a result, we terminated our agreements with this counterparty.  At the time of the termination, we wereholding approximately $1.7 million of collateral from this counterparty;accordingly, we do not expect this bankruptcy filing to have any impact on ourresults of operations, financial position or cash flows.

 

The use offinancial instruments may expose us to the risk of financial loss in somecircumstances, including instances when (i) our equity volumes are less thanexpected, (ii) our customers fail to purchase or deliver the contractedquantities of natural gas or NGLs, or (iii) our OTC counterparties fail toperform.  To the extent that we engagein hedging activities, we may be prevented from realizing the benefits offavorable price changes in the physical market.  However, we are similarly insulated against decreases in theseprices.

 

***Risk Policy andControl.**** *We control the extent of riskmanagement and marketing activities through policies and procedures thatinvolve the senior level of management. On a daily basis, our marketing activities are audited and monitored byour independent risk oversight department, or IRO.  This department reports to the Chief Financial Officer, therebyproviding a separation of duties from the marketing department.  Additionally, the IRO reports monthly to theRisk Management Committee, or RMC.  Thiscommittee is comprised of corporate managers and officers and is responsiblefor developing the policies and guidelines that control the management andmeasurement of risk. The RMC is also responsible for 

 

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setting risk limits includingvalue-at-risk and dollar stop loss limits. Our board of directors approves the risk limit parameters and riskmanagement policy.

 

***HedgePositions.* **Asof July 31, 2003, we have hedged approximately 51% of our projected 2003 equitynatural gas volumes and approximately 78% of our estimated equity production ofcrude oil, condensate, and NGLs.  Wehave also begun to enter into hedges for our projected 2004 equity natural gasvolumes and for our estimated equity production of crude oil, condensate, andNGLs.  All of 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.  We regularly use crude oil swaps in hedging the variability inthe sales price of butanes, which may result in hedge ineffectiveness from timeto time.  During the six months endedJune 30, 2003, we did not recognize any losses from the ineffective portions ofour hedges.  Overall, our hedges areexpected to continue to be “highly effective” under SFAS 133 in the future.

 

To qualify as cashflow hedges, the hedge instruments must be designated as cash flow hedges andchanges in their fair value must be highly correlated with changes in the priceof the forecasted transaction being hedged so that our exposure to the risk ofcommodity price changes is reduced.  Tomeet this requirement, we hedge both the price of the commodity and the basisbetween that derivative’s contract delivery location and the cash marketlocation used for the actual sale of the product.  This structure attains a high level of effectiveness, insuringthat a change in the price of the forecasted transaction will result in anequal and opposite 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.

 

***Outstanding EquityHedge Positions and the Associated Basis for 2003***.  The following table details our hedgepositions as of July 31, 2003.  In orderto determine the hedged price to the particular operating region, deduct thebasis differential from the NYMEX price. The prices for NGLs do not include the cost of the hedges ofapproximately $465,000.

 
| **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  – 20,000 MMbtu per day with an average basis price of ($0.15) per MMbtu.   |
|        |   |                                                                                                                              |   |                                                                                           |
|        |   | 20,000 MMbtu  per day with a minimum price of $3.50 per MMbtu and an average maximum price  of $4.43 per MMbtu.                   |   | Permian –  5,000 MMbtu per day with an average basis price of ($0.13) per MMbtu.          |
|        |   |                                                                                                                              |   | Rocky  Mountain – 45,000 MMbtu per day with an average basis price of ($0.78) 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      |   | 75,000  Barrels per month.  Average minimum  and maximum price of $0.25 per gallon and $0.37 per gallon, respectively.       |   | Not Applicable                                                                                 |

 

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***Outstanding EquityHedge Positions and the Associated Basis for 2004*.**  The following table details our hedgepositions as of July 31, 2003.  In orderto determine the hedged price to the particular operating region, deduct thebasis differential from the NYMEX price. The prices for NGLs do not include the cost of the hedges ofapproximately $339,000.

 
| **Product** |   | **Quantity  and NYMEX or Settlement Price**                                                                                          |   | **Hedge of  Basis Differential**                                                             |
|-------------|--------|--------------------------------------------------------------------------------------------------------------------------------------|--------|----------------------------------------------------------------------------------------------|
| Natural gas |   | 30,000 MMbtu  per day with a minimum price of $4.00 per MMbtu and an average maximum price  of $8.88 per MMbtu.                      |   | Mid-Continent  – 25,000 MMbtu per day with an average basis price of ($0.27) per MMbtu. |
|        |   |                                                                                                                                 |   | Permian –  5,000 MMbtu per day with an average basis price of ($0.34) per MMbtu.        |
|        |   |                                                                                                                                 |   |                                                                                         |
| Crude Oil   |   | 25,000  Barrels of crude oil per month with a minimum price of $22.00 per barrel and  an average maximum price of $30.15 per barrel. |   | Not Applicable                                                                               |
|        |   |                                                                                                                                 |   |                                                                                         |
| Butanes     |   | 25,000  Barrels of crude oil per month.  Floor  at $22.00 per barrel.  (Crude oil is  used as a surrogate for butanes).    |   | Not Applicable                                                                               |

 

Accountbalances related to equity and transportation hedging transactions at June 30,2003 were $2.9 million in Current Assets from price risk management activities,$22.0 million in Current Liabilities from price risk management activities,$800,000 in Non-current assets from price risk management activities, $40,000in Non-current liabilities from price risk management activities, ($6.8)million in Deferred income taxes payable, net, and a $11.8 million after-taxunrealized loss in Accumulated other comprehensive income, a component ofShareholders’ Equity.  Based on pricesas of June 30, 2003, approximately $12.6 million of losses in Accumulated othercomprehensive income will be reclassified to earnings in 2003 and $746,000 ofgains in Accumulated other comprehensive income will be reclassified toearnings in 2004.

 

***Summary ofDerivative Positions.***  A summary of the change in our derivative position from December31, 2002 to June 30, 2003 is as follows (dollars in thousands):

 
| Fair value of contracts outstanding at  December 31, 2002              |   | $       | 63      |   |
|------------------------------------------------------------------------|--------|---------|---------|--------|
| Decrease  in value due to change in price                              |   | (32,762 | )       |
| Increase in value due to new contracts  entered into during the period |   | 19,102  |    |
| Losses realized during the period from  existing and new contracts     |   | 2,329   |    |
| Changes in fair value attributable to  changes in valuation techniques |   | —  |    |
| Fair value of contracts outstanding at June  30, 2003                  |   | $       | (11,268 | )      |
|                                                                        |        |         |         |        |  |

 

A summary ofour outstanding derivative positions at June 30, 2003 is as follows (dollars inthousands):

 
|                             |   | **Fair Value  of Contracts at June 30, 2003** |    |
|----------------------------------|--------|-----------------------------------------------|---------|
| **Source of Fair Value**         |   | **Total Fair  Value**                         |    | **Maturing  In 2003** |   | **Maturing  In 2004-2005** |   | **Maturing  In 2006-2007** |   | **Maturing  Thereafter** |   |
| Exchange published prices        |   | $                                             | (17,728 | ) | $ | (19,314 | ) | $ | 1,586 |   | — |   | — |   |
| Other actively quoted prices (1) |   | 10,774                                        |    | 9,681 |   | 1,101 |   | $ | (8 | ) | — |   |
| Other valuation methods (2)      |   | (4,314                                        | )       | (5,501 | ) | 1,187 |   | — |   | — |   |
| Total fair value                 |   | $                                             | (11,268 | ) | $ | (15,134 | ) | $ | 3,874 |   | $ | (8 | ) | — |   |

 

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

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

 

***Foreign CurrencyDerivative Market Risk***.  As a normal part of our business, we enter into physical gastransactions which are payable in Canadian dollars.  We enter into forward purchases and sales of Canadian dollarsfrom time to time to fix the cost of our future Canadian dollar denominatednatural gas purchase, sale, storage, and transportation obligations.  This is done to protect marketing marginsfrom adverse changes in the U.S. and Canadian dollar exchange rate between the

 

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time the commitment for thepayment obligation is made and the actual payment date of such obligation.  As of June 30, 2003, the net notional valueof such contracts was approximately $12.8 million in Canadian dollars, whichapproximates fair market value.

 

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

 

***Evaluation of disclosure controls andprocedures.***

 

At the end ofthe period covered by this report, we carried out an evaluation, under thesupervision and with the participation of the Company’s management, includingthe Company’s Chief Executive Officer and President and Executive VicePresident and Chief Financial Officer, of the effectiveness of the design andoperation of our disclosure controls and procedures pursuant to Rule 13a-15 ofthe Securities Exchange Act of 1934 (the “Exchange Act”).  Based upon that evaluation, the Company’sChief Executive Officer and President and Executive Vice President and ChiefFinancial Officer concluded that our disclosure controls and procedures areeffective to ensure that information required to be disclosed by the Company inthe reports that it files or submits under the Exchange Act is recorded,processed, summarized and reported within the time periods specified in theSecurities and Exchange Commission’s rules and forms.

 

***Changes in internal controls over financialreporting.***

 

Our Chief Executive Officer andChief Financial Officer have also concluded that there has not been any changein our internal control over financial reporting (as such term is defined inRules 13a-15(f) and 15d-15(f) under the Exchange Act) that has materiallyaffected, or is reasonably likely to materially affect, our internal controlover financial reporting.  There were nosignificant changes in our internal controls or in other factors that couldsignificantly affect these controls subsequent to the date of their evaluation.

 

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

 

**ITEM 1****.****                      LEGALPROCEEDINGS**

 

***WesternGas Resources, Inc. and Lance Oil & Gas Company, Inc. v. WilliamsProduction RMT Company., (Defendant), Civil Action No. CO2-10-394, DistrictCourt, County of Sheridan, Wyoming. *** As reported in our Form 10-Q for the quarterended March 31, 2003, in October 2002, we filed a complaint for declaratoryrelief and damages related to a dispute arising under a development agreementand other agreements between the parties. We amended this complaint in July2003 to assert additional contractual claims, and the Defendant responded withadditional counterclaims seeking declaratory relief and damages.  The dispute centers on Defendant’sacquisition 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 fourthquarter of 2002, the Defendant asserted breach of contract claims againstus.  The Defendant also claimed damagesunder its gathering agreement with us. We believe that the Defendant’s assertions are without merit.  We have also asserted breach of contractclaims against the Defendant for its operating practices.  The parties began mediation of these issuesin the first quarter of 2003.  At thistime, we are unable to predict the outcome of this litigation or the claimsscheduled for mediation.

 

***Price,et al. v. Gas Pipelines, Western Gas Resources, Inc., et al., District Court,Stevens County, Kansas, Case No. 99-C-30.*** As reported in our Form 10-Q for the quarterended March 31, 2003, we are a defendant in litigation filed in 1999,along with numerous other natural gas companies, in which Mr. Price is claimingan under measurement of gas and Btu volumes throughout the country.  We along with other natural gas companiesfiled a motion to dismiss for failure to state a claim.  The court denied these motions to dismiss.   The court denied plaintiff’s motion forcertification as a class and, in the second quarter of 2003, the plaintiff hasamended and refiled for certification as a class.  On May 12, 2003, Mr. Price filed a further claim *Will Price et al v. Gas Resources, Inc. et al.,District Court, Stevens County, Kansas, Case No. 03C23*, relating tocertain matters previoiusly removed from the foregoing action.  We believe that Mr. Price’s claims arewithout merit and intend to vigorously contest the allegations in thiscase.  At this time, we are unable topredict the outcome of this matter.

 

***Wyoming Department of Revenue.**** *As reported in ourForm 10-Q for the quarter ended March 31, 2003, we The WyomingDepartment of Revenue has conducted an audit of Lance Oil & Gas Company,Inc. for the period from January 1, 1998 through December 31, 1999.  On March 24, 2003, the Department of Revenuenotified us that it had assessed additional severance taxes and increasedtaxable value for ad valorem tax purposes. The additional severance and ad valorem taxes claimed by the Department ofRevenue amount to $196,000 and $351,000, respectively, together with statutoryinterest.  We believe that the WyomingDepartment of Revenue claims are without merit and intend to vigorously contesttheir assessments.  On April 23, 2003,we filed a Notice of Appeal with the Wyoming State Board of Equalization.

 

***In the Matter of the Notice of ViolationIssued to Mountain Gas Resources, Inc., Department of Environmental Quality,State of Wyoming. ***InJuly 2003, we received a Notice of Violation issued by the State of WyomingDepartment of Environmental Quality for failing to obtain a permit prior toconstructing certain dehydration units at facilities in Sublette County,Wyoming.  This Notice of Violation wasreceived after we self-reported to the Department of Environmental Quality inApril 2003 that we had inadvertently failed to submit notices of intent and airpermit applications for such dehydration units.  We anticipate that we will be able to resolve this matter in thethird quarter of 2003 and that it will not have a material adverse effect onour financial position, results of operations, or cash flows.

 

***National Pipeline Mapping System***.  In July 2003, we received correspondencefrom the U.S. Department of Transportation regarding our failure to submitinformation for incorporation into the National Pipeline Mapping System withinsix months of enactment of the Pipeline Safety Improvement Act of 2002.  We are working with the U.S. Department ofTransportation Office of Pipeline Safety to supply the requiredinformation.  We are unable to predictwhether we will be subject to any fines or penalties under the Act, and whatthe amount of such fines would be if imposed.

 

***Challenges to the Powder River Basin EIS*.**  On May 1, 2003, two lawsuits were filedchallenging the Federal Bureau of Land Management’s Record of Decision on theEnvironmental Impact Statement issued on April 30, 2003 as it relates to theState of Wyoming.  The respective suitsare *Western Organization of ResourceCouncils vs. Kathleen Clarke et al., Case No. CV-03-70-BLG-RWA, U.S. DistrictCourt for the District of Montana* and *American Lands Alliance v. U.S. Bureau of Land Management et al., CaseNo. CV-03-71-BLG-RWA, U.S. District Court for the District of Montana*.

 

Both theBureau of Land Management and the State of Wyoming have filed separate motionsto dismiss for lack of venue or, in the alternative, to transfer the cases tothe U.S. District Court, for the District of Wyoming.  We, along with various industry companies, have filed motions tointervene and responses to the complaints, including motions to dismiss.  At this time we are unable to predict theoutcome of this matter or its impact on our future development plans in thePowder River Basin.

 

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

 

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**ITEM4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS**

 

The following matters were voted on at ourAnnual Meeting of Stockholders held on May 16, 2003:

 

Joseph E. Reidand Ward Sauvage were elected as Class Two Directors to serve until their termsexpire in 2006 and until their successors have been elected.  A total of 26,484,228 and 26,485,028 shares,respectively, were voted for and 3,679,148 and 3,678,348 shares, respectively,were withheld for Joseph E. Reid and Ward Sauvage.  There were no broker non-votes or abstentions.

 

PricewaterhouseCoopersLLP appointment to serve as our independent auditors for the fiscal year endingDecember 31, 2003 was ratified.  A totalof 30,046,832 shares were voted for, 113,858 were voted against and there were2,686 abstentions.  There were no brokernon-votes or abstentions

 

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**ITEM6.       EXHIBITS AND REPORTS ON FORM 8-K**

 
| (a)    | Exhibits:                                                                                               |
|--------|---------------------------------------------------------------------------------------------------------|
|   |                                                                                                    |
|   | **Exhibit  Number**                                                                                     |   | **Description** |
|   |                                                                                                    |   |   |
|   | 3.1                                                                                                     |   | Certificate of  Incorporation of Western Gas Resources, Inc. (previously filed as Exhibit 3.1  to our Registration Statement on Form S-1, Registration No. 33-31604 and  incorporated herein by reference). |
|   |                                                                                                    |   |   |
|   | 3.2                                                                                                     |   | Certificate of  Amendment to the Certificate of Incorporation of Western Gas Resources, Inc.  (previously filed as Exhibit 3.2 to our Registration Statement on Form S-1,  Registration No. 33-31604 and incorporated herein by reference). |
|   |                                                                                                    |   |   |
|   | 3.3                                                                                                     |   | Certificate  of Designation of 7.25% Cumulative Senior Perpetual Convertible Preferred  Stock of the Company (previously 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). |
|   |                                                                                                    |   |   |
|   | 3.4                                                                                                     |   | Amended and  Restated Bylaws of Western Gas Resources, Inc. adopted by the Board of  Directors on April 7, 2003 (previously filed as Exhibit 3.5 to our Quarterly  Report on Form 10-Q filed on May 13, 2003 and incorporated herein by  reference). |
|   |                                                                                                    |   |   |
|   | 31.1                                                                                                    |   | Section 302  Certification of the Chief Executive Officer. |
|   |                                                                                                    |   |   |
|   | 31.2                                                                                                    |   | Section 302  Certification of the Chief Financial Officer. |
|   |                                                                                                    |   |   |
|   | 32                                                                                                      |   | Section 906  Certification of the Chief Executive Officer and Chief Financial Officer. |
|   |                                                                                                    |   |   |
|   |                                                                                                    |   |   |
| (b)    | Reports on  Form 8-K:                                                                                   |
|   |                                                                                                    |
|   |   During  the quarter ended June 30, 2003, we furnished the following Form 8-K  reports: |
|   |                                                                                                    |
|   |                                                                                                    | • | Current  Report on Form 8-K filed on May 20, 2003 (dated May 19, 2003) announcing the  election of a new Chairman of the Board. |
|   |                                                                                                    |   |   |
|   |                                                                                                    | • | Current  Report on Form 8-K furnished on May 8, 2003 (dated May 8, 2003) announcing  financial results for the quarter ending March 31, 2003. |
|   |                                                                                                    |   |   |
|   |                                                                                                    | • | Current  Report on Form 8-K furnished on August 12, 2003 (dated August 12, 2003)  announcing financial results for the quarter and six months ending June 30,  2003. |
|        |                                                                                                         |  |  |  |  |

 

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SIGNATURES

 

Pursuant to the requirements of theSecurities Exchange Act of 1934, the Registrant has duly caused this report tobe signed on its behalf by the undersigned, thereunto duly authorized.

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

 

 

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Exhibit Index

 
| 3.1    |   | Certificate of  Incorporation of Western Gas Resources, Inc. (previously filed as Exhibit 3.1  to our Registration Statement on Form S-1, Registration No. 33-31604 and  incorporated herein by reference).                                                                                |
|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                       |
| 3.2    |   | Certificate of  Amendment to the Certificate of Incorporation of Western Gas Resources, Inc.  (previously filed as Exhibit 3.2 to our Registration Statement on Form S-1,  Registration No. 33-31604 and incorporated herein by reference).                                                |
|   |   |                                                                                                                                                                                                                                                                                       |
| 3.3    |   | Certificate  of Designation of 7.25% Cumulative Senior Perpetual Convertible Preferred  Stock of the Company (previously 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). |
|   |   |                                                                                                                                                                                                                                                                                       |
| 3.4    |   | Amended and  Restated Bylaws of Western Gas Resources, Inc. adopted by the Board of  Directors on April 7, 2003 (previously filed as Exhibit 3.5 to our Quarterly  Report on Form 10-Q filed on May 13, 2003 and incorporated herein by  reference).                                       |
|   |   |                                                                                                                                                                                                                                                                                       |
| 31.1   |   | Section 302  Certification of the Chief Executive Officer.                                                                                                                                                                                                                            |
|   |   |                                                                                                                                                                                                                                                                                       |
| 31.2   |   | Section 302 Certification  of the Chief Financial Officer.                                                                                                                                                                                                                            |
|   |   |                                                                                                                                                                                                                                                                                       |
| 32.3   |   | Section 906  Certification of the Chief Executive Officer and Chief Financial Officer.                                                                                                                                                                                                |

 

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