10-Q 1 d10q.txt FORM 10Q SECOND QUARTER SECURITIES AND EXCHANGE COMMISSION ---------------------------------- Washington, D.C. 20549 ---------------------- FORM 10-Q (Mark One) ---------- [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2001 OR [_] 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 (I.R.S. Employer incorporation or organization) Identification No.) 12200 N. Pecos Street, Denver, Colorado 80234-3439 -------------------------------------------------------------------------------- (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 the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for 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 X No --- On August 1, 2001, there were 32,653,000 shares of the registrant's Common Stock outstanding. 1 Western Gas Resources, Inc. Form 10-Q Table of Contents
PART I - Financial Information Page ------------------------------ ---- Item 1. Financial Statements Consolidated Balance Sheet - June 30, 2001 and December 31, 2000..................................... 3 Consolidated Statement of Cash Flows - Three and Six Months Ended June 30, 2001 and 2000............................................................................... 4 Consolidated Statement of Operations - Three and Six Months Ended June 30, 2001 and 2000............................................................................... 5 Consolidated Statement of Changes in Stockholders' Equity - Six Months Ended June 30, 2001........................................................................................ 6 Notes to Consolidated Financial Statements........................................................... 7 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations........................................................................................... 12 Item 3. Quantitative and Qualitative Disclosures about Market Risk........................................... 20 PART II - Other Information --------------------------- Item 1. Legal Proceedings.................................................................................... 24 Item 4. Submission of matters to a vote of security holders.................................................. 25 Item 6. Exhibits and Reports on Form 8-K..................................................................... 25 Signatures........................................................................................................... 26
2 PART I - FINANCIAL INFORMATION Item 1. Financial Statements -------------------- WESTERN GAS RESOURCES, INC. CONSOLIDATED BALANCE SHEET (Dollars in thousands, except share data)
June 30, December 31, ASSETS 2001 2000 ------ --------- ---------- (unaudited) Current assets: Cash and cash equivalents................................................................... $ 56,414 $ 12,927 Trade accounts receivable, net.............................................................. 276,079 546,791 Product inventory........................................................................... 67,673 44,822 Parts inventory............................................................................. 3,060 3,489 Assets from price risk management activities................................................ 54,831 - Assets held for sale........................................................................ - 25,001 Other ...................................................................................... 2,177 2,654 ----------- ------------- Total current assets..................................................................... 460,234 635,684 Property and equipment: Gas gathering, processing, storage and transportation....................................... 884,076 856,982 Oil and gas properties and equipment (successful efforts method)............................ 168,889 139,084 Construction in progress.................................................................... 76,577 58,319 ----------- ------------- 1,129,542 1,054,385 Less: Accumulated depreciation, depletion and amortization.................................... (333,781) (306,651) ----------- -------------- Total property and equipment, net........................................................ 795,761 747,734 ----------- ------------- Other assets: Gas purchase contracts (net of accumulated amortization of $34,336 and $33,357, respectively).............................................................................. 33,819 34,798 Assets from price risk management activities................................................ 13,333 - Other ...................................................................................... 13,492 13,206 ----------- ------------- Total other assets.......................................................................... 60,644 48,004 ----------- ------------- Total assets................................................................................... $ 1,316,639 $ 1,431,422 =========== ============= LIABILITIES AND STOCKHOLDERS' EQUITY ------------------------------------ Current liabilities: Accounts payable............................................................................ $ 344,813 $ 581,563 Accrued expenses............................................................................ 43,027 25,094 Liabilities from price risk management activities........................................... 26,488 - Dividends payable........................................................................... 4,217 4,205 ----------- ------------- Total current liabilities................................................................ 418,545 610,862 Long-term debt................................................................................. 305,000 358,700 Liabilities from price risk management activities.............................................. 1,722 - Other long-term liabilities.................................................................... 2,570 2,646 Deferred income taxes payable, net............................................................. 108,657 67,680 ----------- ------------- Total liabilities.............................................................................. 836,494 1,039,888 ----------- ------------- Stockholders' equity: Preferred Stock; 10,000,000 shares authorized: $2.28 cumulative preferred stock, par value $.10; 1,400,000 shares issued ($35,000,000 aggregate liquidation preference)....................................... 140 140 $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; 32,652,057 and 32,361,131 shares issued, respectively ............................................... 3,289 3,265 Treasury stock, at cost; 25,016 common shares and 44,290 $2.28 cumulative preferred shares in treasury.......................................................... (1,907) (1,778) Additional paid-in capital.................................................................. 404,756 400,157 Retained earnings (deficit)................................................................. 49,798 (11,820) Accumulated other comprehensive income...................................................... 24,677 2,178 Notes receivable from key employees secured by common stock................................. (884) (884) ----------- ------------- Total stockholders' equity............................................................... 480,145 391,534 ----------- ------------- Total liabilities and stockholders' equity..................................................... $ 1,316,639 $ 1,431,422 =========== =============
The accompanying notes are an integral part of the consolidated financial statements. 3 WESTERN GAS RESOURCES, INC. CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited) (Dollars in thousands)
Six Months Ended June 30, ------------------------------ 2001 2000 ------------ ------------- Reconciliation of net income to net cash provided by operating activities: Net income ......................................................................... $ 70,043 $ 23,586 Add income items that do not affect cash: Depreciation, depletion and amortization.......................................... 29,761 27,532 Gain on the sale of property and equipment........................................ (11,223) (5,634) Deferred income taxes............................................................. 27,897 13,262 Other non-cash items, net......................................................... (1,693) 880 ------------ ------------ 114,785 59,626 Adjustments to working capital to arrive at net cash provided by operating activities: (Increase) decrease in trade accounts receivable.................................. 263,435 (136,174) (Increase) decrease in product inventory ......................................... (22,851) 3,026 Decrease in parts inventory ...................................................... 429 1,259 Decrease in other current assets.................................................. 477 6,305 (Increase) decrease in other assets and liabilities, net.......................... (75) 6 Increase (decrease) in accounts payable........................................... (236,750) 98,253 Increase (decrease) in accrued expenses........................................... 18,848 (16,556) ------------ ------------ Net cash provided by operating activities........................................... 138,298 15,745 ------------ ------------ Cash flows from investing activities: Purchases of property and equipment............................................... (74,539) (51,216) Proceeds from the dispositions of property and equipment ......................... 38,075 15,916 Contributions to equity investees................................................. (637) - ------------ ------------ Net cash used in investing activities............................................... (37,101) (35,300) ------------ ------------ Cash flows from financing activities: Net proceeds from exercise of common stock options................................ 4,623 259 Repurchase of $2.28 cumulative preferred stock.................................... (129) - Debt issue costs paid............................................................. (91) (5) Payments on revolving credit facility............................................. (344,900) (608,136) Borrowings under revolving credit facility........................................ 291,200 632,386 Dividends paid.................................................................... (8,413) (8,439) ------------ ------------ Net cash provided by financing activities........................................... (57,710) 16,065 ------------ ------------ Net increase (decrease) in cash and cash equivalents................................ 43,487 (3,490) Cash and cash equivalents at beginning of period.................................... 12,927 14,062 ------------ ------------ Cash and cash equivalents at end of period ......................................... $ 56,414 $ 10,572 ============ ============
The accompanying notes are an integral part of the consolidated financial statements. 4 WESTERN GAS RESOURCES, INC. CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited) (Dollars in thousands, except share and per share amounts)
Three Months Ended Six Months Ended June 30, June 30, -------------------------- --------------------------- 2001 2000 2001 2000 ----------- ------------ ------------ ------------ Revenues: Sale of residue gas.......................................... $ 756,526 $ 506,793 $ 1,801,402 $ 919,673 Sale of natural gas liquids.................................. 114,492 122,219 243,969 257,607 Processing, transportation and storage revenue............... 16,304 9,410 30,624 23,295 Unrealized gain (loss) on marketing activities............... (2,873) - 2,176 - Other, net................................................... 2,575 3,394 6,129 6,393 ------------ ------------ ------------ ------------ Total revenues........................................... 887,024 641,816 2,084,300 1,206,968 ------------ ------------ ------------ ------------ Costs and expenses: Product purchases............................................ 784,550 576,727 1,871,150 1,077,870 Plant operating expense...................................... 18,240 17,100 35,277 32,362 Oil and gas exploration and production expense............... 9,098 1,791 18,703 5,937 Depreciation, depletion and amortization .................... 15,283 14,223 29,761 27,532 Gain on sale of assets ...................................... - (335) (11,223) (5,634) Selling and administrative expense........................... 7,545 8,100 16,024 15,489 Interest expense............................................. 5,992 7,809 12,821 16,027 ------------ ------------ ------------ ------------ Total costs and expenses................................. 840,708 625,415 1,972,513 1,169,583 ------------ ------------ ------------ ------------ Income before income taxes..................................... 46,316 16,401 111,787 37,385 Provision for income taxes: Current ..................................................... 5,685 - 13,847 537 Deferred..................................................... 11,178 5,821 27,897 13,262 ------------ ------------ ------------ ------------ Total provision for income taxes......................... 16,863 5,821 41,744 13,799 ------------ ------------ ------------ ------------ Net income..................................................... 29,453 10,580 70,043 23,586 Preferred stock requirements................................... (2,584) (2,610) (5,169) (5,220) ------------- ------------ ------------ ------------ Income attributable to common stock............................ $ 26,869 $ 7,970 $ 64,874 $ 18,366 ============ ============ ============ ============ Earnings per share of common stock............................. $ .82 $ .25 $ 2.00 $ .57 ============ ============ ============ ============ Weighted average shares of common stock outstanding............ 32,579,509 32,196,793 32,492,276 32,181,331 ============ ========== ============ ============ Income attributable to common stock - fully diluted............ $ 28,680 $ 10,396 $ 68,497 $ 10,396 ============ ============ ============ ============ Earnings per share of common stock - fully diluted................................................ $ .77 $ .24 $ 1.85 $ .56 ============ ============ ============ ============ Weighted average shares of common stock outstanding - fully diluted................................................ 37,073,854 32,770,736 36,965,284 32,628,146 ============ ============ ============ ============
The accompanying notes are an integral part of the consolidated financial statements. 5 WESTERN GAS RESOURCES, INC. CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (Unaudited) (Dollars in thousands, except share amounts)
Shares of Shares of $2.625 $2.28 $2.28 Cumulative Shares Cumulative Cumulative Convertible Shares of Common Preferred Preferred Stock Preferred of Common Stock Stock in Treasury Stock Stock in Treasury ---------- --------------- -------- ---------- ----------- Balance at December 31, 2000................... 1,400,000 39,190 2,760,000 32,361,131 25,016 Comprehensive income: Net income, six months ended June 30, 2001.............................. - - - - - Cumulative effect of change in accounting principle - January 1, 2001............... - - - - - Reclassification adjustment for settled contracts................................. - - - - - Changes in fair value of outstanding hedging positions......................... - - - - - Fair value of new hedge positions.......... - - - - - Ending accumulated derivative gain........ - - - - - Translation adjustments...................... - - - - - Total comprehensive income, net of tax....... Stock options exercised........................ - - - 290,926 - Tax benefit related to stock options........... - - - - - Loans forgiven................................. - - - - - Dividends declared on common stock............. - - - - - Dividends declared on $2.28 cumulative preferred stock.............................. - - - - - Dividends declared on $2.625 cumulative convertible preferred stock.................. - - - - - Repurchase of $2.28 cumulative preferred stock.............................. - 5,100 - - - ---------- ---------- ---------- ----------- ---------- Balance at June 30, 2001....................... 1,400,000 44,290 2,760,000 32,652,057 25,016 ========== ========== ========== =========== ========== $2.625 $2.28 Cumulative Cumulative Convertible Additional Preferred Preferred Common Treasury Paid-In Stock Stock Stock Stock Capital ----------- ------------ ---------- ----------- -------- Balance at December 31, 2000................... 140 276 3,265 (1,778) 400,157 Comprehensive income: Net income, six months ended June 30, 2001.............................. - - - - - Cumulative effect of change in accounting principle - January 1, 2001............... - - - - - Reclassification adjustment for settled contracts................................. - - - - - Changes in fair value of outstanding hedging positions......................... - - - - - Fair value of new hedge positions.......... - - - - - Ending accumulated derivative gain........ - - - - - Translation adjustments...................... - - - - - Total comprehensive income, net of tax....... Stock options exercised........................ - - 24 - 4,599 Tax benefit related to stock options........... - - - - - Loans forgiven................................. - - - - - Dividends declared on common stock............. - - - - - Dividends declared on $2.28 cumulative preferred stock.............................. - - - - - Dividends declared on $2.625 cumulative convertible preferred stock.................. - - - - - Repurchase of $2.28 cumulative preferred stock.............................. - - - (129) - ----------- ---------- ---------- ---------- ---------- Balance at June 30, 2001....................... $ 140 $ 276 $ 3,289 $ (1,907) $ 404,756 =========== ========== ========== ========== ========== Accumulated Other Notes Total Retained Comprehensive Receivable Stock- (Deficit) Income from Key holders' Earnings Net of Tax Employees Equity --------- ---------- ---------- ------------ Balance at December 31, 2000................... (11,820) 2,178 (884) 391,534 Comprehensive income: Net income, six months ended June 30, 2001.............................. 70,043 - - 70,043 Cumulative effect of change in accounting principle - January 1, 2001............... - (22,527) - (22,527) Reclassification adjustment for settled contracts................................. - 17,084 - 17,084 Changes in fair value of outstanding hedging positions......................... - 14,494 - 14,494 Fair value of new hedge positions.......... - 13,739 - 13,739 -------- -------- ---------- Ending accumulated derivative gain........ - 22,790 - 22,790 Translation adjustments...................... - (291) - (291) ---------- Total comprehensive income, net of tax....... 92,542 ---------- Stock options exercised........................ - - - 4,623 Tax benefit related to stock options........... - - - - Loans forgiven................................. - - - - Dividends declared on common stock............. (3,257) - - (3,257) Dividends declared on $2.28 cumulative preferred stock.............................. (1,546) - - (1,546) Dividends declared on $2.625 cumulative convertible preferred stock.................. (3,622) - - (3,622) Repurchase of $2.28 cumulative preferred stock.............................. - - - (129) ---------- -------- -------- ---------- Balance at June 30, 2001....................... $ 49,798 $ 24,677 $ (884) $ 480,145 ========== ======== ======== ==========
The accompanying notes are an integral part of the consolidated financial statements. 6 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) GENERAL The interim consolidated financial statements presented herein should be read in conjunction with the Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2000. The interim consolidated financial statements as of June 30, 2001 and for the three and six month periods ended June 30, 2001 and 2000 included herein are unaudited but reflect, in the opinion of management, all adjustments (which include only normal recurring adjustments) necessary to fairly present the results for such periods. The results of operations for the three and six months ended June 30, 2001 are not necessarily indicative of the results of operations expected for the year ended December 31, 2001. Prior year's amounts in the interim consolidated financial statements and notes have been reclassified as appropriate to conform to the presentation used in 2001. EARNINGS PER SHARE OF COMMON STOCK Earnings per share of common stock is computed by dividing income attributable to common stock by the weighted average shares of common stock outstanding. In addition, earnings per share of common stock - assuming dilution is computed by dividing income attributable to common stock by the weighted average shares of common stock outstanding as adjusted for potential common shares. Income attributable to common stock is income less preferred stock dividends. We declared preferred stock dividends of $2.6 million and $5.2 million, respectively, for each of the three and six month periods ended June 30, 2001 and 2000. Common stock options and our $2.625 Cumulative Convertible Preferred Stock, which are potential common shares, had a dilutive effect on earnings and increased the weighted average number of shares of common stock outstanding by 4,494,345 and 573,943 for the three-month periods ended June 30, 2001 and 2000, respectively, and by 4,473,008 and 446,815 for the six months ended June 30, 2001 and 2000, respectively. The numerators and the denominators for these periods were adjusted to reflect these potential shares in calculating fully diluted earnings per share. OTHER INFORMATION Bethel Treating Facility. In December 2000, we signed an agreement with Anadarko Petroleum Corporation for the sale of all the outstanding stock of our wholly-owned subsidiary, Pinnacle Gas Treating, Inc. ("Pinnacle") for $38.0 million. The only asset of this subsidiary was a 300 MMcf per day treating facility and 86 miles of associated gathering assets located in east Texas. The sale closed in January 2001 and resulted in a net pre-tax gain for financial reporting purposes of $11.2 million in the first quarter of 2001. Western Gas Resources-California, Inc. In January 2000, we sold all the outstanding stock of our wholly-owned subsidiary, Western Gas Resources-California, Inc. ("WGR-California") for $14.9 million. The only asset of this subsidiary was a 162 mile pipeline in the Sacramento basin of California. The pipeline was acquired through the exercise of an option by us in a transaction which closed simultaneously with the sale of WGR-California. We recognized a pre-tax gain on the sale of approximately $5.3 million in the first quarter of 2000. The proceeds from these sales were used to reduce borrowings outstanding on the Revolving Credit Facility. Westana. In February 2000, we acquired the remaining 50% interest in the Westana Gathering Company for a net purchase price of $9.8 million. The results from our ownership through February 2000 of a 50% equity interest in the Westana Gathering Company are reflected in revenues in Other, net on the Consolidated Statement of Operations. Beginning in March 2000, the results of these operations are fully consolidated and are included in Revenues and Costs and expenses. Additionally, in March 2000, our investment in the Westana Gathering Company was reclassed from Other assets to Property and equipment. Granger Complex. In May 2001, we acquired the remaining 50% interest in a portion of a gathering system serving the Granger Complex for a net purchase price of $5.9 million in cash and the settlement of previously disclosed litigation. 7 DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES In June 1998, the Financial Accounting Standards Board, the FASB, issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS No. 133"), effective for fiscal years beginning after June 15, 2000. Under SFAS No. 133, which was subsequently amended by SFAS No. 138, we are required to recognize the change in the market value of all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income depending upon the nature of the underlying transaction. Also on January 1, 2001, we adopted mark-to-market accounting for the remainder of our marketing activities which, for various reasons, are not designated or qualified as hedges under SFAS 133. Upon the adoption of SFAS No. 133 and mark-to-market accounting on January 1, 2001, the impact was a decrease in a component of stockholders' equity through Accumulated other comprehensive income of $22.5 million, an increase to Current assets of $52.6 million, an increase to Current liabilities of $86.9 million, an increase to Other long-term liabilities of $1.1 million and a decrease in Deferred income taxes payable of $12.9 million. Of the $22.5 million decrease to Accumulated other comprehensive income resulting from the January 1, 2001 adoption of SFAS 133, $17.1 million was reversed in the first six months of 2001 with gains and losses from the underlying transactions recognized through Total revenues. An additional $4.9 million of this transition entry is currently anticipated to be recognized through Total revenues in the remaining two quarters of 2001. The non-cash impact to our results of operations in the first six months of 2001 resulting from the adoption of mark-to-market accounting for our marketing activities resulted in additional pre-tax income of $2.2 million. The net loss recognized in earnings through Sale of residue gas and Sale of natural gas liquids during the first six months of 2001 from hedging activities was $6.5 million. This includes $184,000 as a result of hedge ineffectiveness due to the use of crude oil swaps in hedging the variability in the sales price of normal butane. All of the company's hedges are expected to continue to be highly effective in the future and no gains or losses were reclassified into earnings as a result of the discontinuance of cash flow hedges. The gains and losses currently reflected in Accumulated other comprehensive income will be reclassified to earnings based on the actual sales of the hedged gas or NGLs. Based on prices as of June 30, 2001, approximately $10.6 million of gains in Accumulated other comprehensive income will be reclassified to earnings in the next twelve months with the remainder reclassified by the end of 2002. ADOPTION OF STOCKHOLDER RIGHTS PLAN In the first quarter of 2001, we adopted a Stockholder Rights Plan under which rights were distributed as a dividend at the rate of one right for each share of our common stock held by stockholders of record as of the close of business on April 9, 2001. The Rights Plan was not adopted in response to any efforts to acquire control of our company. The Rights Plan, however, is designed to deter coercive takeover tactics including the accumulation of shares in the open market or through private transactions and to prevent an acquirer from gaining control of our company without offering a fair and adequate price to all of our stockholders. Each right initially will entitle stockholders to buy one unit consisting of 1/100/th/ of a share of a new series of preferred stock for $180 per unit. The right generally will be exercisable only if a person or group acquires beneficial ownership of 15 percent or more of our then outstanding common stock or commences a tender or exchange offer upon consummation of which a person or group would beneficially own 15 percent or more of our then outstanding common stock. The rights will expire on March 22, 2011. SUPPLEMENTARY CASH FLOW INFORMATION Interest paid was $15.1 million and $17.7 million for the six months ended June 30, 2001 and 2000, respectively. Estimated tax payments of $9.4 million were made during the six months ended June 30, 2001. No income taxes were paid during the six months ended June 30, 2000. SEGMENT REPORTING We operate in four principal business segments, as follows: Gas Gathering and Processing, Production, Marketing and Transmission. These segments are separately monitored by management for performance against our internal forecast and are consistent with our internal financial reporting package. These segments have been identified based upon the differing products and services, regulatory environment and the expertise required for these operations. In our Gas Gathering and Processing segment, we connect producers' wells to our gathering systems for delivery to our processing or treating plants, process the natural gas to extract NGLs and treat the natural gas in order to meet pipeline specifications. Our Marketing segment sells the residue gas and NGLs extracted at our processing facilities. The activities of our Production segment include the exploration and development of gas properties primarily in basins where our gathering and processing facilities are located. Our Marketing segment sells the majority of the production from these properties. 8 Our Marketing segment buys and sells gas and NGLs nationwide and in Canada from or to a variety of customers. In addition, this segment also markets gas and NGLs produced by our gathering, processing and production assets. Our Canadian marketing operations, which are immaterial for separate presentation, are included in this segment. The Marketing segment also includes losses associated with our equity gas and NGL hedging program of $(1.7) million and $(6.5) million for the three months ended June 30, 2001 and June 30, 2000, respectively, and $(16.0) million and $(9.6) million for the six months ended June 30, 2001 and 2000, respectively. The Transmission segment reflects the operations of our MIGC and MGTC pipelines. The majority of the revenue presented in this segment is derived from transportation of residue gas. The following table sets forth our segment information as of and for the three and six months ended June 30, 2001 and 2000 (dollars in thousands). Due to our integrated operations, the use of allocations in the determination of business segment information is necessary. Inter-segment revenues are valued at prices comparable to those of unaffiliated customers.
Gas Gathering Elim- and Trans- inating Processing Production Marketing mission Corporate Entries Total ---------- ---------- ----------- --------- --------- ----------- ---------- Quarter ended June 30, 2001 Revenues from unaffiliated customers... $ 16,165 $ 107 $ 871,397 $ 2,309 $ 21 $ - $ 889,999 Interest income........................ 1 1 - - 3,373 (3,017) 358 Other, net............................. - - (4,409) - 1,076 - (3,333) Intersegment sales..................... 219,730 29,417 9,125 4,391 13 (262,676) - ---------- --------- ----------- --------- --------- ---------- ---------- Total revenues......................... 235,896 29,525 876,113 6,700 4,483 (265,693) 887,024 ---------- --------- ----------- --------- --------- ---------- ---------- Product purchases...................... 182,904 1,964 859,515 434 122 (260,389) 784,550 Plant operating expense................ 16,952 68 80 1,738 (449) (149) 18,240 Oil and gas exploration and production expense............. - 10,591 - - - (1,493) 9,098 ---------- --------- ----------- --------- --------- ---------- ---------- Operating profit....................... $ 36,040 $ 16,902 $ 16,518 $ 4,528 $ 4,810 $ (3,662) 75,136 ========== ========= =========== ========= ========= ========== ========== Depreciation, depletion and amortization.......................... 9,461 3,845 40 419 1,518 - 15,283 Interest expense....................... 5,992 Gain on sale of assets................. - Selling and administrative expense .... 7,545 ---------- Income (loss) before income taxes...... $ 46,316 ========== Identifiable assets.................... $ 581,874 $ 158,517 $ 81 $ 47,796 $ 57,015 $ - $ 845,283 ========== ========= =========== ========= ========= ========== ==========
Gas Gathering Elim- and Trans- inating Processing Production Marketing mission Corporate Entries Total ---------- ---------- ----------- --------- --------- ----------- ---------- Quarter ended June 30, 2000 Revenues from unaffiliated customers... $ 6,768 $ 1,144 $ 637,162 $ 1,877 $ 35 $ 8 $ 646,994 Interest income........................ 1 - 3 - 6,419 (6,353) 70 Other, net............................. 1,692 41 (6,477) - (504) - (5,248) Intersegment sales..................... 186,001 17,603 12,948 4,315 13 (220,880) - ---------- ---------- ----------- --------- --------- ---------- ---------- Total revenues......................... 194,462 18,788 643,636 6,192 5,963 (227,225) 641,816 ---------- ---------- ----------- --------- --------- ---------- ---------- Product purchases...................... 143,245 1,028 647,271 - (65) (214,752) 576,727 Plant operating expense................ 15,416 291 - 1,996 (328) (275) 17,100 Oil and gas exploration and production expense............. 31 8,456 - - - (6,696) 1,791 ---------- ---------- ----------- --------- --------- ---------- ---------- Operating profit....................... $ 35,770 $ 9,013 $ (3,635) $ 4,196 $ 6,356 $ (5,502) $ 46,198 ========== ========== =========== ========= ========= ========== ==========
9 Depreciation, depletion and amortization.......................... 8,991 3,493 40 409 1,290 - 14,223 Interest expense...................... 7,809 Gain on sale of assets................ (335) Selling and administrative expense ... 8,100 ---------- Income (loss) before income taxes..... $ 16,401 ========== Identifiable assets.................... $ 552,073 $ 109,068 $ 68 $ 46,856 $ 38,907 $ - $ 746,972 ========== ========== =========== ========= ========= ========== ==========
Gas Gathering Elim- and Trans- inating Processing Production Marketing mission Corporate Entries Total ---------- ---------- ----------- --------- --------- ----------- ---------- Six months ended June 30, 2001 Revenues from unaffiliated customers... $ 30,200 $ 828 $ 2,058,653 $ 4,984 $ 303 $ - $ 2,094,968 Interest income........................ 1 1 - - 8,459 (7,819) 642 Other, net............................. 4 (1) (13,768) 2 2,453 - (11,310) Intersegment sales..................... 537,803 81,567 20,611 8,658 27 (648,666) - ---------- ---------- ----------- ---------- --------- ----------- ----------- Total revenues......................... 568,008 82,395 2,065,496 13,644 11,242 (656,485) 2,084,300 ---------- ---------- ----------- ---------- --------- ----------- ----------- Product purchases...................... 455,743 4,609 2,047,680 - 135 (637,017) 1,871,150 Plant operating expense................ 32,272 98 119 3,832 (74) (970) 35,277 Oil and gas exploration and production expense............. - 27,645 - - - (8,942) 18,703 ---------- ---------- ----------- ---------- --------- ----------- ----------- Operating profit....................... $ 79,993 $ 50,043 $ 17,697 $ 9,812 $ 11,181 $ (9,556) $ 159,170 ========== ========== =========== ========== ========= =========== =========== Depreciation, depletion and amortization.......................... 18,961 6,912 80 834 2,974 - 29,761 Interest expense....................... 12,821 Gain on sale of assets................. (11,223) Selling and administrative expense .... 16,024 ----------- Income (loss) before income taxes...... $ 111,787 =========== Identifiable assets.................... $ 581,874 $ 158,517 $ 81 $ 47,796 $ 57,015 $ - $ 845,283 ========== ========= =========== ========== ========= =========== ===========
Gas Gathering Elim- and Trans- inating Processing Production Marketing mission Corporate Entries Total ---------- ---------- ----------- --------- --------- ----------- ---------- Six months ended June 30, 2000 Revenues from unaffiliated customers... $ 18,174 $ 2,130 $ 1,189,494 $ 4,255 $ 61 $ - $ 1,214,114 Interest income........................ 34 2 27 - 12,257 (12,021) 299 Other, net............................. 1,672 41 (9,690) - 532 - (7,445) Intersegment sales..................... 320,343 27,907 39,281 8,719 17 (396,267) - ---------- ---------- ----------- --------- --------- ----------- ----------- Total revenues......................... 340,223 30,080 1,219,112 12,974 12,867 (408,288) 1,206,968 ---------- ---------- ----------- --------- --------- ----------- ----------- Product purchases...................... 246,253 1,532 1,219,958 - (90) (389,783) 1,077,870 Plant operating expense................ 28,478 308 - 4,264 (72) (616) 32,362 Oil and gas exploration and production expense.............. 31 12,602 - - - (6,696) 5,937 ---------- ---------- ----------- --------- --------- ----------- ----------- Operating profit....................... $ 65,461 $ 15,638 $ (846) $ 8,710 $ 13,029 $ (11,193) $ 90,799 ========== ========== =========== ========= ========= =========== =========== Depreciation, depletion and amortization.......................... 17,562 6,382 80 833 2,675 - 27,532
10 Interest expense..................... 16,027 Gain on sale of assets............... (5,634) Selling and administrative expense... 15,489 ----------- Income (loss) before income taxes.... $ 37,385 =========== Identifiable assets.................. $ 552,073 $ 109,068 $ 68 $ 46,856 $ 38,907 $ - $ 746,972 ========== ========== =========== ========= ========= =========== ===========
LEGAL PROCEEDINGS Reference is made to "Part II - Other Information - Item 1. Legal Proceedings," of this Form 10-Q. 11 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS ----------------------------------------------------------------------- OF OPERATIONS ------------- The following discussion and analysis relates to factors which have affected our consolidated financial condition and results of operations for the three and six months ended June 30, 2001 and 2000. Prior year amounts have been reclassified as appropriate to conform to the presentation used in 2001. You should also refer to our interim consolidated financial statements and notes thereto included elsewhere in this document. This section, as well as other sections in this Form 10-Q, contain "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995, which can be identified by the use of forward-looking terminology, such as "may," "intend," "will," "expect," "anticipate," "estimate," or "continue" or the negative thereof or other variations thereon or comparable terminology. In addition to the important factors referred to herein, numerous factors affecting the gas processing industry generally and in the specific markets for gas and NGLs in which we operate could cause actual results to differ materially from those in such forward-looking statements. Results of Operations Three and six months ended June 30, 2001 compared to the three and six months ended June 30, 2000 (Dollars in thousands, except per share amounts and operating data).
Three Months Ended Six Months Ended June 30, June 30, ----------------------- Percent --------------------------- Percent 2001 2000 Change 2001 2000 Change ---------- ---------- ------ ------------ ------------ ------ Financial results: Revenues........................................ $ 887,024 $ 641,816 38 $ 2,084,300 $ 1,206,968 73 Gross profit.................................... 59,853 32,310 85 140,632 68,901 104 Net income...................................... 29,453 10,580 178 70,043 23,586 197 Income per share of common stock................ .82 .25 228 2.00 .57 251 Income per share of common stock - fully diluted.............................. .77 .24 221 1.85 .56 230 Net cash provided by operating activities.......................... $ 31,754 $ 5,925 436 $ 138,298 $ 15,745 778 Operating data: Average gas sales (MMcf/D)...................... 1,835 1,670 10 1,755 1,735 1 Average NGL sales (MGal/D)...................... 2,370 2,815 (16) 2,300 2,970 (23) Average gas prices ($/Mcf)...................... $ 4.53 $ 3.34 36 $ 5.68 $ 2.91 95 Average NGL prices ($/Gal)...................... $ .53 $ .48 10 $ .58 $ .48 21
Net income increased $18.9 million and $46.5 million for the three and six months ended June 30, 2001 compared to 2000. The increase in net income for these periods is primarily attributable to significantly higher gas and NGL prices in 2001 compared to the prior year, increased production from the Powder River basin coal bed methane development, and improved results from our marketing segment. Revenues from the sale of gas increased $249.7 million to $756.5 million for the three months ended June 30, 2001 compared to the same period in 2000. This increase was primarily due to an improvement in product prices in 2001 and to a lesser extent an increase in sales of natural gas purchased from third parties. Average gas prices realized by us increased $1.19 per Mcf to $4.53 per Mcf for the quarter ended June 30, 2001 compared to the same period in 2000. Included in the realized gas price were approximately $795,000 of losses recognized in the three months ended June 30, 2001 related to futures positions on equity gas volumes. We have entered into additional futures positions for the majority of our equity gas for the remainder of 2001 and in 2002. See further discussion in " - Liquidity and Capital Resources - Risk Management Activities." Average gas sales volumes increased 165 MMcf per day to 1,835 MMcf per day for the quarter ended June 30, 2001 compared to the same period in 2000. Revenues from the sale of gas increased $881.7 million to $1,801.4 million in the six months ended June 30, 2001 compared to the same period in 2000. This increase was primarily due to an improvement in product prices. Average gas prices realized by us increased $2.77 per Mcf to $5.68 per Mcf in the six months ended June 30, 2001 compared to the same period in 2000. Included in the realized gas price were approximately $14.3 million of losses recognized in the six months 12 ended June 30, 2001 related to futures positions on equity gas volumes. We have entered into additional futures positions for the majority of our equity gas for the remainder of 2001 and in 2002. See further discussion in " - Liquidity and Capital Resources - Risk Management Activities." Average gas sales volumes increased 16 MMcf per day to 1,751 MMcf per day in the six months ended June 30, 2001 compared to the same period in 2000. Revenues from the sale of NGLs decreased $7.7 million in the second quarter of 2001 compared to the same period in 2000. This decrease is due to a reduction in sales volume which more than offset an increase in product prices. Average NGL prices realized by us increased $.05 per gallon to $.53 per gallon in the second quarter of 2001 compared to the same period in 2000. Included in the realized NGL price were approximately $730,000 of losses recognized in the second quarter of 2001 related to futures positions on equity NGL volumes. We have entered into additional futures positions for a portion of our equity NGL production for the remainder of 2001. See further discussion in " - Liquidity and Capital Resources - Risk Management Activities." Average NGL sales volumes decreased 445 MGal per day to 2,370 MGal per day in the second quarter of 2001 compared to the same period in 2000. This decrease is primarily due to an intentional reduction in the sale of third-party product as these types of sales were generating minimal margins. Revenues from the sale of NGLs decreased approximately $13.6 million in the six months ended June 30, 2001 compared to the same period in 2000. This decrease is due to a reduction in sales volume which more than offset an increase in product prices. Average NGL prices realized by us increased $.10 per gallon to $.58 per gallon in the six months ended June 30, 2001 compared to the same period in 2000. Included in the realized NGL price were approximately $1.7 million of losses recognized in the six months ended June 30, 2001 related to futures positions on equity NGL volumes. We have entered into additional futures positions for a portion of our equity NGL production for the remainder of 2001. See further discussion in " - Liquidity and Capital Resources - Risk Management Activities." Average NGL sales volumes decreased 670 MGal per day to 2,300 MGal per day in the six months ended June 30, 2001 compared to the same period in 2000. This decrease is primarily due to an intentional reduction in the sale of third-party product as these types of sales were generating minimal margins. Also contributing to the reduction in overall sales volume was a decrease in the sale of product produced at our facilities as we rejected ethane for a portion of the six month period. Product purchases increased by $207.8 million and $793.3 million for the quarter and six months ended June 30, 2001 compared to the same period in 2000 primarily as a result of the increase in commodity prices. Overall, combined product purchases as a percentage of sales of all products decreased to 90% and 91% for the quarter and six months ended June 30, 2001 from 92% for the same periods in 2000, respectively. The decrease in the product purchase percentage resulted from improved marketing margins. Marketing margins on residue gas averaged $0.10 per Mcf in both the second quarter and the six months ended June 30, 2001. This represents a significant increase as compared to the margin realized during the second quarter of 2000 of $.01 per Mcf and during the six months ended June 30, 2000 of $.02 per Mcf, respectively. The increase in margin for the quarter and six months ended June 30, 2001 primarily resulted from the mark-to-market of transactions utilizing our firm transportation capacity during July through December 2001, and the mark-to-market of storage transactions entered into in the first six months of 2001. The increase in margin for the quarter and six months ended June 30, 2001 primarily resulted from the mark-to-market of contracts for firm transportation capacity during July through December 2001 from Wyoming to the Mid-continent where regional differentials widened and the mark-to-market of storage transactions entered into in the first six months of 2001. Under mark-to-market accounting, which was adopted on January 1, 2001, the margin to be realized over the term of the transaction is recorded in the month of origination. To the extent this amount includes margin to be recognized beyond the current quarter, it is included in the financial statement caption Unrealized gain (loss) on marketing activities. Marketing margins on NGLs averaged approximately $0.007 per gallon in both the second quarter and the six months ended June 30, 2001. This margin remained relatively constant to the same periods in 2000. There is no assurance, however, that these market conditions for our gas and NGL products and related margins will continue in the future, that we will be in a similar position to benefit from them or that we will continue to originate the same amount of transactions in future quarters. In addition, during the first quarter of 2001, we reserved a total of $1.0 million for doubtful accounts. This reserve is not included in the calculation of the marketing margins and is reported in Selling and administrative expenses. Plant operating expense increased $1.1 million in the second quarter of 2001 and by $2.9 million in the six months ended June 30, 2001 compared to the same periods in 2000. This increase is primarily due to additional leased compression in the Powder River basin coal bed development and higher fuel costs at our plant facilities. Oil and gas exploration and production expenses increased by $7.3 million and $12.8 million in the second quarter and the six months ended June 30, 2001 as compared to the same periods in 2000 primarily as a result of our increasing operations in the Powder River basin coal bed methane development. 13 Depreciation, depletion and amortization increased by $1.1 million and $2.2 million in the second quarter and the six months ended June 30, 2001 as compared to the same periods in 2000 primarily as a result of our increasing operations in the Powder River basin coal bed methane development. Other Information Bethel Treating Facility. In December 2000, we signed an agreement with Anadarko Petroleum Corporation for the sale of all the outstanding stock of our wholly-owned subsidiary, Pinnacle Gas Treating, Inc. ("Pinnacle") for $38.0 million. The only asset of this subsidiary was a 300 MMcf per day treating facility and 86 miles of associated gathering assets located in east Texas. The sale closed in January 2001 and resulted in a net pre-tax gain for financial reporting purposes of $11.2 million in the first quarter of 2001. Western Gas Resources-California, Inc. In January 2000, we sold all the outstanding stock of our wholly-owned subsidiary, Western Gas Resources- California, Inc. ("WGR-California") for $14.9 million. The only asset of this subsidiary was a 162 mile pipeline in the Sacramento basin of California. The pipeline was acquired through the exercise of an option by us in a transaction which closed simultaneously with the sale of WGR-California. We recognized a pre-tax gain on the sale of approximately $5.3 million in the first quarter of 2000. The proceeds from these sales were used to reduce borrowings outstanding on the Revolving Credit Facility. Westana. In February 2000, we acquired the remaining 50% interest in the Westana Gathering Company for a net purchase price of $9.8 million. The results from our ownership through February 2000 of a 50% equity interest in the Westana Gathering Company are reflected in revenues in Other, net on the Consolidated Statement of Operations. Beginning in March 2000, the results of these operations are fully consolidated and are included in Revenues and Costs and expenses. Additionally, in March 2000, our investment in the Westana Gathering Company was reclassed from Other assets to Property and equipment. Granger Complex. In May 2001, we acquired the remaining 50% interest in a portion of a gathering system serving the Granger Complex for a net purchase price of $5.9 million in cash and the settlement of previously disclosed litigation. Business Strategy Improved product prices throughout 2000 and continuing into 2001 have strengthened our financial position allowing us to emphasize the growth aspects of our business strategy. Our long-term business plan is to increase our profitability by: (i) optimizing the efficiency and utilization of our existing operations; (ii) developing natural gas reserves and increasing production volumes on our existing acreage positions; and (iii) investing in projects or acquiring assets that complement and extend our core natural gas gathering, processing, production and marketing businesses. We are actively evaluating acquisitions of either assets or companies. These acquisitions can be related to gathering and processing or production with emphasis on properties located in the Rocky Mountains or Canada. Capital expenditures budgeted for existing operations in 2001 are estimated to be approximately $172.7 million. This includes approximately $100.2 million related to gathering, processing and pipeline assets and approximately $46.8 million for the acquisition of undeveloped acreage and development of gas reserves in the Powder River basin. This budget will be increased to provide for acquisitions if approved by our board of directors. In the first six months of 2001, our capital expenditures totaled $75.2 million. We consistently seek to improve the profitability of our existing operations by increasing natural gas throughput levels through new well connections and expansion of our gathering systems, increasing our efficiency through the modernization of equipment and consolidation of existing gathering and processing facilities, evaluating the economic performance of each of our operating facilities to ensure that a targeted rate of return is achieved and controlling operating and overhead expenses. We continually seek to increase reserves dedicated to our gathering and processing facilities. Our operations are located in some of the most actively drilled oil and gas producing basins in the United States. We enter into agreements under which we gather and process natural gas produced on acreage dedicated to us by third parties. We contract for production from new wells or undeveloped acreage in order to replace declines in existing reserves or increase reserves that are dedicated for gathering and processing at our facilities. At December 31, 2000, our estimated dedicated reserves totaled 2.7 Tcf. In 2000, 14 including the reserves developed by us and associated with our partnerships and excluding the reserves and production associated with the facilities sold during this period, we connected new reserves to our facilities to replace approximately 222% of throughput. In order to obtain additional dedicated acreage and to secure contracts on favorable terms, we may participate to a limited extent with third-party producers in exploration and production activities to supply our facilities. For the same reason, we may also offer to sell ownership interests in our facilities to selected producers. We selectively participate in exploration and production activities largely to secure additional gas supply for our facilities. Beginning in 1997, we substantially increased our investment in the acquisition of undeveloped acreage and development of the Powder River basin coal bed methane. We have acquired drilling rights on approximately 520,000 net acres in the basin. At December 31, 2000 we had proved developed and undeveloped reserves of approximately 350 Bcf on a portion of this acreage. We also have participated in the development of properties in southwest Wyoming and Colorado. As of December 31, 2000, these properties had an additional 58 Bcf of proved developed and undeveloped reserves. This represents an increase of approximately 50% in our proved reserves from December 31, 1999. We currently estimate a net total of 2.2 Tcf of probable or possible reserves on an unrisked basis associated with undeveloped acreage in these areas. There can be no assurance, however, as to the ultimate recovery of these probable or possible reserves. We will also consider investing in other exploration and production prospects that we consider to be low risk and complementary to our other business segments. We will continue to invest in projects that complement and extend our core natural gas gathering, processing, production and marketing businesses including the consideration of expansion into additional geographic areas in the continental United States and Canada. In the third quarter of 2000, our board of directors began a search to identify and evaluate both internal and external candidates to replace our current Chief Executive Officer and President, Lanny Outlaw who had informed the board of his intention to retire May 31, 2001 in accordance with his contract. In May 2001, Mr. Outlaw agreed to postpone his retirement until November 30, 2001 in order to allow the board of directors additional time to secure the ideal candidate as his successor. Mr. Outlaw intends to serve his remaining term on the board of directors which expires in May 2003. Liquidity and Capital Resources Our sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under our financing facilities and proceeds from offerings of debt and equity securities. In the past, these sources have been sufficient to meet our needs and finance the growth of our business. We can give no assurance that the historical sources of liquidity and capital resources will be available for future development and acquisition projects, and we may be required to seek alternative financing sources. Product prices, sales of inventory, the volumes of natural gas processed by our facilities, the volume of natural gas produced from our producing properties, the margin on third-party product purchased for resale, as well as the timely collection of our receivables will all affect future net cash provided by operating activities. Additionally, our future growth will be dependent upon obtaining additions to dedicated plant reserves, acquisitions, new project development, marketing, efficient operation of our facilities and our ability to obtain financing at favorable terms. We believe that the amounts available to be borrowed under the Revolving Credit Facility, together with net cash provided by operating activities will provide us with sufficient funds to connect new reserves, maintain our existing facilities, complete our current capital expenditure program and make any scheduled debt principal payments. Depending on the timing and the amount of our future projects, we may be required to seek additional sources of capital. Our ability to secure such capital is restricted by our financing facilities, although we may request additional borrowing capacity from our lenders, seek waivers from our lenders to permit us to borrow funds from third parties, seek replacement financing facilities from other lenders, use stock as a currency for acquisitions, sell existing assets or a combination of alternatives. While we 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 of any additional financing. We also believe that cash provided by operating activities and amounts available under the Revolving Credit Facility will be sufficient to meet our debt service and preferred stock dividend requirements for 2001. During the past several years some of our plants have experienced declines in dedicated reserves, overall we have been successful in connecting additional reserves to more than offset the natural declines. Higher gas prices, improved technology, e.g. 3-D seismic and horizontal drilling, and increased pipeline capacity from the Rocky Mountain region have stimulated drilling in many of our operating areas. The overall level of drilling will depend upon, among other factors, the prices for oil and gas, the drilling budgets of third-party producers, the energy policy and regulation by governmental agencies and the 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 the dedicated reserves processed at our facilities. 15 We have effective shelf registration statements filed with the Commission for an aggregate of $200 million of debt securities and preferred stock, along with the shares of common stock, if any, into which those securities are convertible, and $62 million of debt securities, preferred stock or common stock. Our sources and uses of funds for the six months ended June 30, 2001 are summarized as follows (dollars in thousands): Sources of funds: Borrowings under the Revolving Credit Facility............................. $ 291,200 Proceeds from the dispositions of property and equipment................... 38,075 Net cash provided by operating activities.................................. 138,298 Proceeds from exercise of common stock options............................. 4,623 ------------- Total sources of funds................................................ $ 472,196 ============= Uses of funds: Payments related to long-term debt (including debt issue costs)............ $ 344,900 Capital expenditures....................................................... 74,539 Dividends paid............................................................. 8,413 Other...................................................................... 857 ------------- Total uses of funds................................................... $ 428,709 =============
Additional sources of liquidity available to us are our inventories of gas and NGLs in storage facilities. We store gas and NGLs primarily to ensure an adequate supply for long-term sales contracts and for resale during periods when prices are favorable. We held gas in storage and in imbalances of approximately 11.5 Bcf at an average purchase cost of $5.61 per Mcf at June 30, 2001 compared to 9.5 Bcf at an average purchase cost of $3.06 per Mcf at June 30, 2000 under storage contracts at various third-party facilities. These positions will be substantially liquidated within the next twelve months at prices prevailing at that time as adjusted by any associated derivative instruments. Under mark-to- market accounting, the profit to be earned on these transactions was recorded in the month of origin. We held NGLs in storage of 6,930 MGal, consisting primarily of propane and normal butane, at an average cost of $0.45 per gallon and 8,670 MGal at an average cost of $0.34 per gallon at June 30, 2001 and 2000, respectively, at various third-party storage facilities. At June 30, 2001, we had no significant hedging contracts in place for anticipated sales of stored NGLs. Preferred Stock Repurchase Program Through the first six months of 2001, we purchased in open market transactions a total of 5,100 shares of our $2.28 cumulative preferred stock for a total cost, including broker commissions, of approximately $129,000, or an average of $25.25 per share of preferred stock. These shares will be retired. Our board of directors has authorized the re-purchase from time to time of up to an additional $1.0 million of preferred stock in open market transactions. Capital Investment Program Primarily as a result of additional drilling behind our systems and in the Powder River Basin, we have increased our capital budget for the year ending December 31, 2001 by approximately $36.3 million. We now expect capital expenditures related to existing operations to be approximately $172.7 million during 2001, consisting of the following: (i) approximately $100.2 million related to gathering, processing and pipeline assets, of which $8.5 million is for maintaining existing facilities; (ii) approximately $64.8 million related to exploration and production activities; and (iii) approximately $7.7 million for miscellaneous items. Overall, capital expenditures in the Powder River basin coal bed methane development and in southwest Wyoming operations represent 40% and 20%, respectively, of the total 2001 budget. As of June 30, 2001, we have expended $75.2 million, consisting of the following: (i) $37.2 million related to gathering, processing and pipeline assets, of which $2.6 million is for maintaining existing facilities; (ii) $35.4 million related to exploration and production activities; and (iii) $2.6 million for miscellaneous items. Coal Bed Methane - We continue to develop our Powder River basin coal bed gas reserves and the associated gathering system in Wyoming. The Powder River Basin coal bed methane area is currently one of the largest on-shore plays for the development of natural gas in the United States. In the first six months of 2001, we continued to be the largest producer of 16 natural gas (together with our partner), the largest gatherer of natural gas and the largest gas transporter out of the basin. At June 30, 2001, we held the drilling rights on approximately 780,000 gross acres, or 520,000 net acres, in the basin. As of December 31, 2000, we had established proven developed and undeveloped reserves totaling 350 Bcf on a portion of this acreage. This represented a 50% increase in proved reserves as compared to December 31, 1999. As of June 30, 2001, we estimated that there was a net total of 2.1 Tcf of probable and possible reserves on an unrisked basis associated with undeveloped acreage in this area. There can be no assurance, however, as to the ultimate recovery of these reserves. We participated in the drilling of 310 wells in the first half of 2001 and plan to participate in a total of 840 wells in 2001. The average drilling, completion and gathering cost for our coal bed methane gas wells is approximately $70,000 to $90,000 per well with proved reserves per well of approximately 330 MMcf. Our average finding and development costs in this area are estimated to be $.30 per Mcf. As deeper wells are drilled to the Big George coal, reserves per well are expected to increase as will the average cost per well. It is expected that the deeper Big George wells will result in a higher rate of return. Total production from wells in which we own an interest has increased from an average of approximately 128 MMcf per day at December 31, 1999 to 219 MMcf per day at June 30, 2001. We currently anticipate production rates of 270 MMcf per day from this area by the end of 2001 and 300 MMcf per day from this area by March 31, 2002. This represents a three month delay in achieving our production goals due to several factors. These factors include weather delays during the spring drilling season, delays in receiving water discharge permits and less than forecasted production from the Hoe Creek area. Within the Hoe Creek area, approximately 150 gross wells have not responded to de-watering as expected and may not achieve our original estimate of production or reserves. All of the remaining areas under development in the Wyodak coal continue to produce at or above forecasted levels. We are currently evaluating eight pilot development areas in the Big George. Several of these pilots are in close proximity to leases operated by third- parties which are currently producing growing volumes of natural gas. By the end of 2001, we expect to have drilled 250 gross wells in the pilot areas. Five of these pilot areas are currently in the de-watering phase. Our All Night Creek pilot is currently producing 450 Mcf per day of gas from 18 wells. An additional 10 wells in this area are capable of producing gas, but are shut in as a result of regulations restricting the venting of natural gas. Compression is expected to be operational by late August and all 28 wells should then begin delivering gas to market. Future drilling on federal acreage will be delayed subject to completion of the Powder River Basin Oil & Gas Environmental Impact Statement. We anticipate the study to be completed in the third quarter of 2002. Our drilling plans for 2001 are not expected to be substantially impacted by this study due to our large inventory of non-federal drilling locations and the issuance of drilling permits by the Bureau of Land Management, BLM, for approximately 250 well locations to prevent drainage of federal acreage. Additionally, the Wyoming Department of Environmental Quality, DEQ, has revised some standards for surface water discharge that have allowed the issuance of most of the permits that apply to the Cheyenne and Belle Fourche drainage areas. We continue to work with both the Wyoming DEQ and Montana DEQ to finalize an agreement between the agencies allowing for water discharge in the Powder River drainage area in which most of our Big George prospects are located. We anticipate that the Wyoming DEQ will begin issuing permits for the Powder River drainage area in the third quarter of 2001. The majority of wells on our acreage producing from the Wyodak formation drain into the Cheyenne and Belle Fourche drainage areas. We can make no assurance that the conditions under which additional permits will be granted will not impact the level of drilling or the timing of production. In addition to the revenues earned from the production of our coal bed methane gas, we also earn fees for gathering and transporting the natural gas. At June 30, 2001, we were gathering 283 MMcf per day of our own production and of other third-party producers. Of that volume, approximately 136 MMcf per day was transported through our MIGC pipeline. Our capital budget in this area provides for expenditures of approximately $67.2 million during 2001. This capital budget includes approximately $46.8 million for drilling costs for our interest in approximately 840 wells, production equipment and undeveloped acreage and $20.4 million for compression. Depending upon future drilling success, we may need to make additional capital expenditures to continue expansion in this basin. Due to drilling and regulatory uncertainties which are beyond our control, we can make no assurance that we will incur this level of capital expenditure. In the first six months of 2001, capital expenditures in this area totaled $39.5 million. In 1998, we joined with other industry participants to form Fort Union Gas Gathering, L.L.C., to construct a 106-mile long, 24-inch gathering pipeline and treater to gather and treat natural gas in the Powder River basin in northeast Wyoming. We own a 13% equity interest in Fort Union and are the construction manager and field operator. The gathering header has a capacity of approximately 435 MMcf per day and in June 2001 it had throughput of approximately 310 MMcf per day. The header delivers coal bed methane gas to a treating facility near Glenrock, Wyoming and accesses interstate pipelines serving gas markets in the Rocky Mountain and Midwest regions of the United States. In 1999, we entered into a ten year agreement 17 for firm gathering services on 60 MMcf per day of capacity at $.14 per Mcf on Fort Union. In the fourth quarter of 2000, we and the other participants in the Fort Union Gas Gathering, L.L.C. approved an expansion of the system. Construction of the 62 mile expansion has begun and will increase the system capacity by an additional 200 MMcf per day. This project is expected to be completed in the third quarter of 2001. This expansion, which is anticipated to cost $25.7 million, will be project financed and will require a cash investment by us of approximately $500,000. Also in connection with the expansion, we will increase our commitment for firm gathering services by an additional 23 MMcf per day of capacity at $.14 per Mcf . Southwest Wyoming. Our facilities in southwest Wyoming are comprised of the Granger and Lincoln Road facilities, or collectively the Granger Complex, and our Red Desert facility. These facilities have a combined operational capacity of 327 MMcf per day and processed an average of 183 MMcf per day in the first six months of 2001. Our capital budget in this area provides for expenditures of approximately $35.2 million during 2001. This capital budget includes approximately $14.4 million for drilling costs and production equipment and approximately $20.8 million related to the gathering systems and plant facilities. Due to drilling and regulatory uncertainties which are beyond our control, we can make no assurance that we will incur this level of capital expenditure. During the first six months of 2001, we expended $13.9 million in this area which includes the purchase of the remaining 50% interest in a gathering system serving the Granger Complex. Under a 1997 agreement with an active producer in this area, we participate in approximately 248,000 gross acres, or approximately 35,000 net acres. In 2001, we expect to participate in 8 gross development wells, or 2 net development wells, in the Jonah field of southwest Wyoming. We also expect to participate in the drilling of up to 38 gross wells, or 2 net wells in the Pinedale Anticline area of the Hoback basin during 2001. The expected drilling and completion costs per gross well are approximately $2.4 million to $3.5 million and the average well depth in this area approximates 13,000 feet. Our average finding and development costs are estimated to be $.57 per Mcf. We have established proven developed and undeveloped reserves totaling 52 Bcf at December 31, 2000. This represents a 73% increase as compared to December 31, 1999. As of June 30, 2001, we estimate a net total of 102 Bcf of probable and possible reserves on an unrisked basis associated with undeveloped acreage in this area. There can be no assurance, however, as to the ultimate recovery of these reserves. Financing Facilities Revolving Credit Facility. The Revolving Credit Facility is with a syndicate of banks and provides for a maximum borrowing commitment of $250 million consisting of an $83 million 364-day Revolving Credit Facility, or Tranche A, and a $167 million Revolving Credit Facility, or Tranche B, which matures on April 30, 2004. At June 30, 2001, no amounts were outstanding under this facility. The Revolving Credit Facility bears interest at certain spreads over the Eurodollar rate, or the greater of the Federal Funds rate or the agent bank's prime rate. We have the option to determine which rate will be used. We also pay a facility fee on the commitment. The interest rate spreads and facility fee are adjusted based on our debt to capitalization ratio and range from .75% to 2.00%. At June 30, 2001, the interest rate payable on any borrowings under this facility would have been approximately 5.0%. We are required to maintain a total debt to capitalization ratio of not more than 55%, and a senior debt to capitalization ratio of not more than 40% through December 31, 2001 and of not more than 35% thereafter. The agreement also requires a quarterly test of the ratio of EBITDA (excluding some non-recurring items) for the last four quarters, to interest and dividends on preferred stock for the same period. The ratio must exceed 1.80 to 1.0 through September 30, 2001 and increases periodically to 3.25 to 1.0 by December 31, 2002. This facility is guaranteed and secured via a pledge of the stock of some of our subsidiaries. Master Shelf Agreement. In December 1991, we entered into a Master Shelf Agreement with The Prudential Insurance Company of America. Amounts outstanding under the Master Shelf Agreement at June 30, 2001 are as indicated in the following table (dollars in thousands):
Interest Final Issue Date Amount Rate Maturity Principal Payments Due ------------------ -------- -------- ---------------- ------------------------------------------------ October 27, 1992 $ 25,000 7.99% October 27, 2003 $8,333 on each of October 27, 2001 through 2003 December 27, 1993 25,000 7.23% December 27, 2003 single payment at maturity October 27, 1994 25,000 9.05% October 27, 2001 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 -------- $150,000 ========
Under our agreement with Prudential, we are required to maintain a current ratio, as defined therein, of at least .9 to 1.0, a minimum tangible net worth equal to the sum of $300 million plus 50% of consolidated net earnings earned from January 1, 1999 plus 75% of the net proceeds of any equity offerings after January 1, 1999, a total debt to capitalization ratio of not 18 more than 60% through December 31, 2001 and of not more than 55% thereafter and a senior debt to capitalization ratio of not more than 40% through March 2002 and not more than 35% thereafter. This agreement also requires an EBITDA to interest ratio of not less than 3.00 to 1.0 increasing to a ratio of not less than 3.75 to 1.0 by March 31, 2002 and an EBITDA to interest on senior debt ratio of not less than 4.75 to 1.0 increasing to a ratio of not less than 5.50 to 1.0 by March 31, 2002. EBITDA in these calculations excludes certain non- recurring items. In addition, this agreement contains a calculation limiting dividends under which approximately $87.0 million was available at June 30, 2001. We are currently paying an annual fee of 0.50% on the amounts outstanding on the Master Shelf Agreement. This fee will continue until we receive an implied investment grade rating on our senior secured debt from Moody's Investors Service or Standard & Poor's. Borrowings under the Master Shelf Agreement are guaranteed and secured via a pledge of the stock of some of our subsidiaries. In October 2001, we have principal payments totaling $33.3 million due under the Master Shelf Agreement. We expect to use funds available under the Revolving Credit Facility to make these payments. Senior Subordinated Notes. In 1999, we sold $155.0 million of Senior Subordinated Notes in a private placement with a final maturity of 2009 due in a single payment which were subsequently exchanged for registered publicly tradeable notes under the same terms and conditions. The Subordinated Notes bear interest at 10% per annum and were priced at 99.225% to yield 10.125%. These notes contain maintenance covenants which include limitations on debt incurrence, restricted payments, liens and sales of assets. The Subordinated Notes are unsecured and are guaranteed on a subordinated basis by some of our subsidiaries. We incurred approximately $5.0 million in offering commissions and expenses which have been capitalized and will be amortized over the term of the notes. Covenant Compliance. We were in compliance with all covenants in our debt agreements at June 30, 2001. Taking into account all the covenants contained in these agreements, we had approximately $250 million of available borrowing capacity at June 30, 2001. 19 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ---------------------------------------------------------- Risk Management Activities Our commodity price risk management program has two primary objectives. The first goal is to preserve and enhance the value of our equity volumes of gas and NGLs with regard to the impact of commodity price movements on cash flow, net income and earnings per share in relation to those anticipated by our operating budget. The second goal is to manage price risk related to our gas, crude oil and NGL marketing activities to protect profit margins. This risk relates to hedging fixed price purchase and sale commitments, preserving the value of storage inventories, reducing exposure to physical market price volatility and providing risk management services to a variety of customers. We utilize a combination of fixed price forward contracts, exchange-traded futures and options, as well as fixed index swaps, basis swaps and options traded in the over-the-counter, or OTC, market to accomplish these objectives. These instruments allow us to preserve value and protect margins because corresponding losses or gains in the value of the financial instruments offset gains or losses in the physical market. We use futures, swaps and options to reduce price risk and basis risk. Basis is the difference in price between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. We enter into futures transactions on the New York Mercantile Exchange, or NYMEX, and the Kansas City Board of Trade and through OTC swaps and options with various counter parties, consisting primarily of financial institutions and other natural gas companies. We conduct our standard credit review of OTC counter parties and have agreements with these parties that contain collateral requirements. We generally use standardized swap agreements that allow for offset of positive and negative exposures. OTC exposure is marked-to-market daily for the credit review process. Our OTC credit risk exposure is partially limited by our ability to require a margin deposit from our major counter parties based upon the mark-to-market value of their net exposure. We are subject to margin deposit requirements under these same agreements. In addition, we are subject to similar margin deposit requirements for our NYMEX counter parties related to our net exposures. The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (i) equity volumes are less than expected, (ii) our customers fail to purchase or deliver the contracted quantities of natural gas or NGLs, or (iii) our OTC counter parties fail to perform. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against decreases in these prices. For the remaining two quarters of 2001, we have entered into hedging positions for approximately 80,000 MMbtus per day of our equity gas volumes at an average of $4.36 per MMbtu. These positions represent approximately 70 percent of our projected equity gas volumes in 2001. For 2002, we have hedged approximately 80,000 MMbtus per day, or 57 percent of our projected 2002 equity gas production, with collar structures providing for an average minimum price of $3.81 per MMbtu and an average maximum price of $5.87 per MMbtu. These prices are NYMEX-equivalents. As of June 30, 2001, we had purchased puts for 125,000 barrels per month, for the remainder of 2001, of NYMEX monthly average settlement of $23.96 per barrel to hedge a portion of our equity production of natural gasoline, condensates, butanes and crude oil . As of June 30, 2001, we had purchased puts for 125,000 barrels per month, for the remainder of 2001, of OPIS Mt. Belvieu monthly average settlement of $.434 per gallon to hedge a portion of our equity production of propane for 2001. As of June 30, 2001, we had purchased puts for 60,000 barrels per month, for the remainder of 2001, of OPIS Mt. Belvieu monthly average settlement of $.3175 per gallon of purity ethane to hedge a portion of our equity production of ethane for 2001. As of June 30, 2001, we did not hold any crude oil or NGL futures, swaps or options for settlement beyond 2001. We enter into speculative futures, swap and option trades on a very limited basis for purposes that include testing of hedging techniques. Our policies contain strict guidelines for such trading including predetermined stop-loss requirements and 20 net open positions limits. Speculative futures, swap and option positions are marked-to-market at the end of each accounting period and any gain or loss is recognized in income for that period. Net gains or losses from such speculative activities for the quarters ended June 30, 2001 and 2000 were not material. Foreign Currency Derivative Market Risk. As a normal part of our business, we enter into physical gas transactions which are payable in Canadian dollars. We enter into forward purchases and sales of Canadian dollars from time to time to fix the cost of our future Canadian dollar denominated natural gas purchase, sale, storage and transportation obligations. This is done to protect marketing margins from adverse changes in the U.S. and Canadian dollar exchange rate between the time the commitment for the payment obligation is made and the actual payment date of such obligation. As of June 30, 2001, the net notional value of such contracts was approximately $18.8 million in Canadian dollars, which approximates its fair market value. Accounting for Derivative Instruments and Hedging Activities. In June 1998, the Financial Accounting Standards Board, the FASB, issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS No. 133"), effective for fiscal years beginning after June 15, 2000. Under SFAS No. 133, which was subsequently amended by SFAS No. 138, we are required to recognize the change in the market value of all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income depending upon the nature of the underlying transaction. Also on January 1, 2001, we adopted mark-to-market accounting for the remainder of our marketing activities which, for various reasons, are not designated or qualified as hedges under SFAS 133. Upon the adoption of SFAS No. 133 and mark-to-market accounting on January 1, 2001, the impact was a decrease in a component of stockholders' equity through Accumulated other comprehensive income of $22.5 million, an increase to Current assets of $52.6 million, an increase to Current liabilities of $86.9 million, an increase to Other long-term liabilities of $1.1 million and a decrease in Deferred income taxes payable of $12.9 million. Of the $22.5 million decrease to Accumulated other comprehensive income resulting from the January 1, 2001 adoption of SFAS 133, $17.1 million was reversed in the first six months of 2001 with gains and losses from the underlying transactions recognized through operating income. An additional $4.9 million of this transition entry is currently anticipated to be recognized through operating income in the remaining two quarters of 2001. The non-cash impact to our results of operations in the first six months of 2001 resulting from the adoption of mark-to-market accounting for our marketing activities resulted in additional pre-tax income of $2.2 million. 21 Principal Facilities The following tables provide information concerning our principal facilities at June 30, 2001. We also own and operate several smaller treating, processing and transmission facilities located in the same areas as our other facilities.
Average for the Six Months Ended June 30, 2001 Gas Gas --------------------------------------------- Gathering Throughput Gas Gas NGL Year Placed System Capacity Throughput Production Production Facilities (1) In Service Miles (2) (MMcf/D) (3) (MMcf/D) (4) (MMcf/D) (5) (MGal/D) (5) ------------------------------------ ---------- --------- ------------ ------------ ------------ ------------ Texas Gomez Treating.................... 1971 385 280 104 96 - Midkiff/Benedum................... 1955 2,188 165 146 95 876 Mitchell Puckett Gathering........ 1972 91 120 79 51 - Louisiana Toca (7)(8)....................... 1958 - 160 115 111 92 Wyoming Coal Bed Methane Gathering....................... 1990 1,100 223 261 242 - Fort Union Gas Gathering ......... 1999 106 450 277 277 - Granger (7)(9)(10)................ 1987 494 235 151 129 283 Hilight Complex (7)............... 1969 626 80 15 11 57 Kitty/Amos Draw (7)............... 1969 314 17 9 6 37 Lincoln Road (10) ................ 1988 149 50 18 16 30 Newcastle (7)..................... 1981 146 5 3 2 18 Red Desert (7).................... 1979 111 42 14 13 25 Reno Junction (9)................. 1991 - - - - 94 Oklahoma Chaney Dell ...................... 1966 2,066 180 70 57 113 Westana .......................... 1986 965 45 61 54 33 New Mexico San Juan River (6)................ 1955 140 60 26 21 15 Utah Four Corners Gathering............ 1988 104 15 2 2 5 ------- ------- ------ ------ ------ Total........................... 8,985 2,127 1,351 1,183 1,678 ======= ======= ====== ====== ====== Average for the Six Months Ended June 30, 2001 -------------------------------- Pipeline Gas Year Placed Transmission Capacity Throughput Transmission Facilities (1) In Service Miles (2) (MMcf/D) (2) (MMcf/D) (4) -------------------------------- ---------- -------------- ------------ ------------ MIGC (11)(13).................... 1970 245 147 184 MGTC (12)........................ 1963 252 18 11 ------- ----- ------- Total......................... 497 165 195 ======= ===== =======
Footnotes on following page. 22 (1) Our interest in all facilities is 100% except for Midkiff/Benedum (73%), Newcastle (50%) and Fort Union Gas Gathering (13%). We operate all facilities and all data includes our interests and the interests of other joint interest owners and producers of gas volumes dedicated to the facility. Unless otherwise indicated, all facilities shown in the table are gathering and processing facilities. (2) Gas gathering system miles, interconnect and transmission miles, and pipeline capacity are as of June 30, 2001. (3) Gas throughput capacity is as of June 30, 2001 and represents capacity in accordance with design specifications unless other constraints exist, including permitting or field compression limits. (4) Aggregate wellhead natural gas volumes collected by a gathering system or volumes transported by a pipeline. (5) Volumes of gas and NGLs are allocated to a facility when a well is connected to that facility; volumes exclude NGLs fractionated for third parties. (6) Sour gas facility (capable of processing or treating gas containing hydrogen sulfide and/or carbon dioxide). (7) Fractionation facility (capable of fractionating raw NGLs into end-use products). (8) Straddle plant, or a plant located near a transmission pipeline that processes gas dedicated to or gathered by a pipeline company or another third party. (9) NGL production includes conversion of third-party feedstock to iso- butane. (10) We are currently processing all gas gathered through the Lincoln Road gathering system at our Granger facility. (11) MIGC is an interstate pipeline located in Wyoming and is regulated by the Federal Energy Regulatory Commission. (12) MGTC is a public utility located in Wyoming and is regulated by the Wyoming Public Service Commission. (13) Pipeline capacity represents capacity at the Powder River junction only and does not include northern delivery points. 23 PART II - OTHER INFORMATION Item 1. Legal Proceedings ----------------- Western Gas Resources, Inc., Mountain Gas Resources, Inc., v. R.I.S. Resources International Corporation, a British Columbia , Canada corporation; RIS Resources (USA) Inc., a Texas Corporation, United States District Court, Colorado, Civil Action No. 00-S-599. As previously disclosed, our subsidiary Mountain Gas was a defendant in prior litigation, styled as McMurry Oil Company, et al. v. TBI Exploration, Inc., Mountain Gas Resources, Inc. and Wildhorse Energy Partners, LLC, District Court, Ninth Judicial District, Sublette County, Wyoming, Civil Action No. 5882, which was settled on all issues for substantially less than the amount claimed. Western and Mountain Gas were seeking reimbursement from RIS Resources, (USA), Inc., Mountain Gas' joint venture partner, for 50% of the settlement amount which was paid in full by Mountain Gas. In May 2001, we acquired RIS' 50% interest in a portion of a gathering system serving the Granger Complex for a net purchase price of $5.9 million in cash and the settlement of this litigation. Western Gas Resources, Inc., v. Amerada Hess Corporation, District Court, Denver County, Colorado, Civil Action No. 00-CV-1433. As previously disclosed, we were a defendant in prior litigation, styled as Berco Resources, Inc. v. Amerada Hess Corporation and Western Gas Resources, Inc., United States District Court, District of Colorado, Civil Action No. 97-WM-1332, which has been settled for an amount which did not have a material impact on our results of operations or financial position. We are seeking reimbursement from Amerada Hess under a contractual indemnity. Amerada Hess sought a motion to dismiss, which was denied. We have amended our original complaint and requested a jury trial in this case. The parties are proceeding with discovery. Barrett Resources Corporation and Lance Oil & Gas Company, Inc., (collectively Plaintiffs) v. Westport Oil and Gas Company, Inc., (Defendant) Civil Action No. 00CV6973, District Court, City and County of Denver, Colorado. On September 15, 2000 Plaintiffs filed a complaint for damages and declaratory relief related to a dispute arising under a Farmout Agreement between the parties dated September 26, 1995, as amended. The dispute centers on Plaintiffs' alleged delay of drilling of wells on a portion of the acreage covered by the Farmout Agreement. In October 2000, Defendant counterclaimed that the Farmout Agreement was terminated due to Plaintiffs' alleged delay of drilling. In July 2001, Plaintiffs notified Defendant of the commencement of drilling eleven wells on the acreage covered by the Farmout Agreement. In August 2001, Defendant filed supplemental counterclaims which included claims for trespass, conversion, accounting and constructive trust on the eleven wells drilled by Plaintiff and compensatory and exemplary damages in connection with these wells. A trial for this case is set for December 3, 2001 and the parties are currently proceeding with discovery. We intend to vigorously defend against the counterclaims but cannot express an opinion as to the outcome of this litigation. We believe that any unfavorable outcome will not have a material adverse effect on our financial condition. Other. We are involved in various other litigation and administrative proceedings arising in the normal course of our business. In the opinion of management, any liabilities that may result from these claims will not, individually or in the aggregate, have a material adverse effect on our financial position or results of operations. 24 Item 4. Submission of Matters to a Vote of Security Holders --------------------------------------------------- The following matters were voted on at our Annual Meeting of Stockholders held on May 18, 2001: Walter L. Stonehocker, Dean Phillips, Bill M. Sanderson, and James A. Senty were elected as Class Three Directors to serve until their terms expire in 2004 and until their successors have been elected. A total of 25,992,081, 26,071,914, 26,022,139 and 26,072,061 shares, respectively, were voted for and 328,033, 248,200, 297,975, and 248,053 shares respectively, were withheld for Walter L. Stonehocker, Dean Phillips, Bill M. Sanderson, and James A. Senty. Item 6. Exhibits and Reports on Form 8-K -------------------------------- (a) Exhibits: 3.3 Amended and Restated Bylaws of Western Gas Resources, Inc. adopted by the Board of Directors on July 13, 2001. 10.7 Form of revised Employment Agreement with exhibit thereto by and between Western Gas Resources, Inc. and its Executive Officers dated June 14, 2001. 10.27 Amendment to Employment Agreement by and between Western Gas Resources, Inc. and Lanny F. Outlaw its Chief Executive Officer and President dated May 18, 2001. (b) Reports on Form 8-K: None 25 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. WESTERN GAS RESOURCES, INC. --------------------------- (Registrant) Date: August 13, 2001 By: /s/ LANNY F. OUTLAW ------------------------------------- Lanny F. Outlaw Chief Executive Officer and President Date: August 13, 2001 By: /s/ WILLIAM J. KRYSIAK ------------------------------------- William J. Krysiak Vice President - Finance (Principal Financial and Accounting Officer) 26 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. WESTERN GAS RESOURCES, INC. --------------------------- (Registrant) Date: August 13, 2001 By: ------------------------------- Lanny F. Outlaw Chief Executive Officer and President Date: August 13, 2001 By: ------------------------------- William J. Krysiak Vice President - Finance (Principal Financial and Accounting Officer) 27