WGR Western Gas Res

Western Gas Resources, Inc. Announces Second Quarter 2004 Results DENVER, Aug. 5 /PRNewswire-FirstCall/ -- Western Gas Resources, Inc. (NYSE:WGR) today announced that for the quarter ended June 30, 2004, it had net income of $14.0 million or earnings of $0.19 per share of common stock. This compares to net income of $20.9 million or earnings of $0.28 per share of common stock for the same period in 2003. Revenues for the quarter ended June 30, 2004 totaled $726.3 million. Results for the second quarter of 2004 include the effect of a $6.7 million after-tax charge related to the previously announced redemption of the Company's 10% Senior Subordinated Notes and a $7.0 million after-tax charge related to a previously announced settlement with the Commodity Futures Trading Commission. In total these items reduced earnings per share of common stock by $0.18. For the six months ended June 30, 2004, net income was $43.1 million, or earnings of $0.58 per share of common stock. This compares to net income of $44.3 million, or earnings of $0.59 per share of common stock, for the same period in 2003. Revenues for the six months ended June 30, 2004 were $1.5 billion. Results for the six months ended June 30, 2004 include the effect of the previously discussed $6.7 million and $7.0 million after-tax charges and the benefit from the cumulative effect of a change in accounting principle. In total these items reduced earnings per share of common stock by $0.12. Results for the six months ended June 30, 2003 include a reduction of earnings per share of common stock from the cumulative effect of a change in accounting principle of $0.09. Earnings per share for all periods are on a fully-diluted basis and are after giving effect to preferred stock dividends. All earnings per share amounts for 2003 have been restated to reflect the two for one stock split completed on June 18, 2004. For the second quarter of 2004, Adjusted EBITDA (earnings before interest, debt prepayment charges, taxes, depreciation and amortization) was $65.0 million and cash flow before working capital adjustments was $55.1 million. For the six months ended June 30, 2004, Adjusted EBITDA (earnings before interest, debt prepayment charges, taxes, depreciation and amortization and the cumulative effect of a change in accounting principle), was $131.8 million and cash flow before working capital adjustments was $116.0 million. Volumes and prices. Net production was 13.6 billion cubic feet equivalent ("Bcfe") in the second quarter of 2004 and averaged 150 million cubic feet equivalent per day ("MMcfed"), representing a slight increase compared to the same period of 2003. Natural gas equity production sold, which includes the effect of prior period adjustments and sales imbalances, was 13.5 Bcfe in the second quarter of 2004, or 148 MMcfed. Gas throughput volumes at the Company's gathering and processing facilities were 1.3 billion cubic feet per day ("Bcfd") in the second quarter of 2004, unchanged compared to the second quarter of 2003. Total gas sales volumes marketed, including equity gas production, gas produced at the Company's plants and gas purchased from third parties for resale, were 1.2 Bcfd in the second quarter of 2004, a slight decrease compared to the same period in 2003. Average gas prices increased 12 percent to $5.49 per thousand cubic feet ("Mcf") in the second quarter of 2004 compared to $4.91 per Mcf for the same period in 2003. Total natural gas liquids ("NGLs") sales volumes marketed averaged 1.6 million gallons per day ("MMGald") in both the second quarter of 2004 and in the same period in 2003. Average NGL prices increased 24 percent to $0.68 per gallon in the second quarter of 2004 compared to $0.55 per gallon in the same period in 2003. Operations. The Company's fully integrated operations include exploration, production, gathering, processing, transportation and marketing of natural gas and NGLs. Exploration and production realized segment-operating profit of $36.6 million for the second quarter of 2004 compared to $28.5 million for the same period in 2003. This increase was primarily due to substantially higher natural gas prices. Gathering and processing realized segment-operating profit of $41.0 million for the second quarter of 2004 compared to $26.2 million for the second quarter of 2003. This increase is primarily due to higher commodity prices and improved contract terms in the Powder River Basin. Gas transportation realized segment-operating profit of $2.5 million for the second quarter of 2004 compared to $2.9 million for the second quarter of 2003. The transportation segment includes the results from the MIGC and MGTC pipelines in the Powder River Basin. Marketing realized segment-operating profit of $3.3 million for the second quarter of 2004 compared to $8.8 million for the same period in 2003. The results for the marketing business in 2003 benefited significantly from transactions utilizing the Company's firm transportation capacity between the Rocky Mountain region and the Mid-Continent markets when price differentials were substantially more than in 2004. Powder River Basin Coal Bed Methane ("CBM"). In the second quarter of 2004, Powder River Basin CBM net production increased three percent to 10.6 Bcfe compared to the first quarter of 2004 and was seven percent less than the same period last year. Net CBM production sold, which includes the effect of prior period adjustments, increased seven percent to 10.8 Bcfe in the second quarter of 2004 compared to the first quarter of 2004, but decreased three percent from the same period last year. The Company, with its partner, continues to be the largest producer of methane in the basin. As of July 2004, gross CBM production from wells in which the Company has an interest in the Big George coal was approximately 57 MMcfd of gas from five development areas, an increase of approximately 78 percent from a year ago. Overall, total industry production from the Big George coal has increased to approximately 137 MMcfd as of May 2004. Based on drilling and permitting progress to date, the Company expects to reach its 2004 goal of participating in 800 CBM wells in the Powder River Basin, including 500 wells in the Big George coal. Western averaged 399 MMcfd of CBM gathering volumes, including third-party gas, during the second quarter of 2004, compared to 414 MMcfd in the same period in 2003. Of that volume, approximately 113 MMcfd was transported through the Company's MIGC pipeline. The Company remains the largest gatherer and transporter of coal bed methane in the Powder River Basin. Greater Green River Basin. Net production from the Pinedale Anticline, Jonah Field and Sand Wash Basin development areas in southwest Wyoming and northwest Colorado was 2.9 Bcfe in the second quarter of 2004 and averaged 32 MMcfed, an increase of 40 percent compared to the same period last year. Net production sold, which includes the result of imbalances, increased nine percent to 2.7 Bcfe net in the second quarter of 2004 compared to the same period last year. In 2004, Western plans to participate in approximately 70 gross wells on the Pinedale Anticline. Ten gross wells are planned in the Sand Wash Basin, of which five have been drilled in the first six months of 2004. Capital Expenditures. The Company increased its budget for capital expenditures in 2004 to $339.7 million, including $82.2 million for the previously announced acquisition of upstream and midstream assets in the San Juan Basin. The revised 2004 capital budget includes approximately $142.1 million for exploration and production and lease acquisition activities, $104.6 million for midstream activities and $10.8 million for administrative and capitalized costs. Balance sheet. At June 30, 2004, Western had total assets of $1.5 billion, cash and cash equivalents in short-term investments of $2.9 million, total long-term debt outstanding of $285 million and a debt to capitalization ratio, net of cash and cash equivalents, of 32 percent. CEO comments. Peter Dea, President and Chief Executive Officer, commented, "The realization and outlook for strong commodity prices, volume growth and our low cost structure continue to benefit and sustain our shareholders for value appreciation. Our integrated approach to developing and delivering unconventional Rocky Mountain natural gas to much needed U.S. markets continues to prove very successful. Our Big George CBM production from the Powder River Basin continues to increase from our current development areas and more pilot areas are expected to begin producing gas shortly. In the Pinedale Anticline, the recently received approval to downspace our leasehold from 40 to 20 acres, will provide additional production and reserves to our interest throughout the decade." Operational performance guidance for the remainder of 2004. Operational performance guidelines for 2004 were provided in a press release by the Company dated February 13, 2004 and updated May 6, 2004. The following information, which includes the impact of the pending San Juan acquisition, represents modifications to the previous guidance. Production. Production volumes are expected to average 162 MMcfed net during the second half of 2004. This includes 121 MMcfd of CBM production in the Powder River Basin, 34 MMcfed from the Greater Green River Basin and seven MMcfd in the San Juan Basin. For the full year 2004 production volumes are expected to be 154 MMcfed, an increase of four percent compared to 2003. Lease operating expense for all production is expected to average approximately $0.67 per Mcf for the remainder of the year, which includes production overhead of $0.10 per Mcf. Other miscellaneous expenses, which includes land and exploration costs, are expected to be $0.09 per Mcf. The Company follows the successful efforts method of accounting for oil and gas exploration and production activities. Gathering and Processing. Throughput volumes for the second half of 2004 are expected to average 1.3 to 1.4 Bcfd. Plant gas sales are expected to average 360 MMcfd and plant NGL sales are expected to average 1.4 MMGald for the second half of 2004. The gross operating margin (gross revenues less product purchase expenses) for the gathering and processing business is expected to average approximately $0.50 per Mcf of facility throughput for the remainder of 2004. Gross operating margin is dependent on commodity prices, and these estimates are based on an assumption of $5.75 per Mcf for natural gas and $38 per barrel for crude oil (NYMEX-equivalent prices.) Plant operating expenses are expected to average $0.18 per Mcf of throughput for the second half of 2004. Transportation. Gas transportation and sales volumes are expected to be approximately 155 MMcfd and revenues are projected to be approximately $11.0 million for the remainder of 2004. Operating income, after deducting pipeline operating expense and product purchase expense, is expected to be approximately $5.0 million for the remainder of 2004. Marketing. Total gas sales volumes marketed (which include production, plant and third-party gas) are expected to be 1.3 Bcfd for the last six months of 2004. Total NGL sales volumes marketed, including plant and third party volumes, are expected to average 1.6 MMgald for the last six months of 2004. NGL marketing margins are expected to average approximately $0.01 per gallon. These assumptions include the impact of mark-to-market accounting for the Company's marketing activities. Other expenses. General and administrative expenses are expected to be $19.8 million, depreciation, depletion and amortization expenses are expected to be $46.2 million and interest expenses are estimated to be $6.8 million for the second half of 2004. The provision for income taxes for the remainder of the year is expected to be approximately 37 percent. Earnings conference call. Western invites you to participate in its second quarter 2004 earnings conference call today at 9:30 a.m. (Mountain Time) by dialing (719) 457-2727. Please dial in five to ten minutes before the start of the call. A replay of the conference call will be available through midnight, August 11, 2004 by dialing (719) 457-0820 (passcode 369953). The live conference call may also be accessed on the Internet by logging onto Western's Web site at http://www.westerngas.com/. Select Financial/Investor Information followed by the Current News option on the menu. Log on at least ten minutes prior to the start of the call to register, download and install any necessary audio software. An audio replay will be available on the web site through August 31, 2004. Company description. Western is an independent natural gas explorer, producer, gatherer, processor, transporter and energy marketer providing a broad range of services to its customers from the wellhead to the sales delivery point. The Company's producing properties are located primarily in Wyoming, including the developing Powder River Basin coal bed methane play, where Western is a leading acreage holder and producer, and the rapidly growing Pinedale Anticline. The Company also designs, constructs, owns and operates natural gas gathering, processing and treating facilities in major gas-producing basins in the Rocky Mountain, Mid-Continent and West Texas regions of the United States. For additional Company information, visit Western's web site at http://www.westerngas.com/. This press release contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 regarding commodity prices, expenses, sales and operating margins, sales volumes, acquisitions, capital expenditures, drilling activity and production volumes for the remainder of 2004. Although the Company believes that its expectations are based on reasonable assumptions, Western can give no assurances that its goals will be achieved. These statements are subject to a number of risks and uncertainties, which may cause actual results to differ materially. These risks and uncertainties include, among other things, changes in natural gas and NGL prices, government regulation or action, litigation, environmental risk, geological risk, weather, rig availability, transportation capacity and other factors as discussed in the Company's 10-K and 10-Q Reports and other filings with the Securities and Exchange Commission. Financial Results: (Dollars in thousands except share and per share amounts) Quarter Six Months Ended June 30, Ended June 30, 2004 2003 2004 2003 Revenues: Sale of gas $595,793 $558,921 $1,260,991 $1,352,191 Sale of natural gas liquids 102,021 80,783 194,936 172,832 Gathering, processing and transportation revenues 24,410 21,458 41,239 41,235 Price risk management activities 3,548 (1,421) (1,820) (19,115) Other, net 531 750 2,173 1,454 Total revenues 726,303 660,491 1,497,519 1,548,597 Costs and expenses: Product purchases 602,166 559,836 1,259,508 1,331,438 Plant and transportation operating expense 22,255 22,612 44,189 44,534 Oil and gas exploration and production expense 19,812 13,290 36,922 25,801 Depreciation, depletion and amortization 22,348 17,685 44,974 35,828 Selling and administrative expense 17,255 9,923 27,201 20,515 (Gain) loss from asset sales 1,639 (195) 1,639 86 (Earnings) from equity investments (1,776) (1,867) (3,702) (3,429) Interest expense 5,351 6,429 11,153 13,243 Loss from early extinguishment of debt 10,662 -- 10,662 -- Total costs and expenses 699,712 627,713 1,432,546 1,468,016 Income before taxes 26,591 32,778 64,973 80,581 Provision for income taxes 12,616 11,878 26,624 29,582 Net income before cumulative effect of changes in accounting principles 13,975 20,900 38,349 50,999 Cumulative effect of changes in accounting principles, net of tax -- -- 4,714 (6,724) Net income 13,975 20,900 43,063 44,275 Preferred stock requirements (19) (1,811) (835) (3,623) Net income available to common stock $13,956 $19,089 $42,228 $40,652 Weighted average shares of common stock outstanding 73,158,240 66,295,886 70,942,578 66,235,624 Earnings per share of common stock $0.19 $0.29 $0.60 $0.61 Weighted average shares of common stock - assuming dilution 75,329,143 74,526,718 72,820,040 74,416,882 Earnings per share of common stock - assuming dilution $0.19(1) $0.28(2) $0.58(3) $0.59(4) (1) Fully-diluted earnings per share for the quarter ended June 30, 2004 include, as potential common shares, the issuance of 1.9 million common shares from the possible exercise of stock options and 249,000 common shares upon an assumed conversion of the $2.625 cumulative convertible preferred stock, and also include an assumed reduction of preferred dividends of $19,000 in determining income attributable to common stock. (2) Fully-diluted earnings per share for the quarter ended June 30, 2003 include, as potential common shares, the issuance of 1.3 million common shares from the possible exercise of stock options and 6.9 million common shares upon assumed conversion reduction of preferred dividends of $1.8 million. (3) Fully-diluted earnings per share for the six months ended June 30, 2004 include, as potential common shares, the issuance of 1.9 million common shares from the possible exercise of stock options. (4) Fully-diluted earnings per share for the six months ended June 30, 2003 include, as potential common shares, the issuance of 1.2 million common shares from the possible exercise of stock options and 6.9 million common shares upon an assumed conversion of the $2.625 cumulative convertible preferred stock, and also include an assumed reduction of preferred dividends of $3.6 million in determining income attributable to common stock. Condensed Consolidated Balance Sheet: (Dollars in thousands) As of As of June 30, December 31, 2004 2003 Assets: Current assets $389,047 $387,303 Property and equipment, net 1,040,140 996,761 Other assets 70,650 76,460 Total assets $1,499,837 $1,460,524 Liabilities and Stockholders' Equity: Liabilities: Current liabilities $388,937 $358,981 Long-term debt 285,000 339,000 Other liabilities 227,812 200,034 Total liabilities 901,749 898,015 Stockholders' equity 598,088 562,509 Total liabilities and stockholders' equity $1,499,837 $1,460,524 Reconciliation of Net Income to Adjusted EBITDA: (Dollars in thousands) Quarter Six Months Ended June 30, Ended June 30, 2004 2003 2004 2003 Net income $13,975 $20,900 $43,063 $44,275 Add: Cumulative effect of change in accounting principle, net of tax -- -- (4,714) 6,724 Depreciation, depletion and amortization 22,348 17,685 44,974 35,828 Interest Expense 5,351 6,429 11,153 13,243 Loss from early extinguishment of debt 10,662 -- 10,662 -- Income taxes 12,616 11,878 26,624 29,582 Adjusted EBITDA $64,952 $56,892 $131,762 $129,652 Reconciliation of Net Income to Cash Flow before Working Capital Adjustments: (Dollars in thousands) Quarter Six Months Ended June 30, Ended June 30, 2004 2003 2004 2003 Net income $13,975 $20,900 $43,063 $44,275 Add income items that do not affect operating cash flows: Depreciation, depletion and amortization 22,348 17,685 44,974 35,828 Deferred income taxes 13,624 9,806 24,089 26,989 Distributions less than equity income, net 1,795 (1,387) 335 44 (Gain) loss on sale of property and equipment 1,639 (195) 1,639 86 Non-cash change in fair value of derivatives (1,523) (3,683) 4,696 480 Compensation expense from repriced stock options 295 381 476 528 Foreign currency translation adjustments 424 105 (1,104) 687 Cumulative effect of changes in accounting principles -- -- (4,714) 6,724 Other non-cash items 2,536 (239) 2,584 (244) Cash flow before working capital adjustments $55,113 $43,373 $116,038 $115,397 Operating Results: (Dollars in thousands except per Mcfe, per Mcf and per Gal amounts) Quarter Six Months Ended June 30, Ended June 30, 2004 2003 2004 2003 Exploration and Production: Average gas production - net volumes sold (MMcfed) 148 149 147 148 Average gas price ($/Mcfe) (1) $4.61 $4.05 $4.51 $4.46 Gathering and transportation expense ($/Mcfe) $0.73 $0.65 $0.72 $0.68 Average wellhead gas price ($/Mcfe) (2) $3.88 $3.40 $3.79 $3.78 Production taxes ($/Mcfe) $0.48 $0.42 $0.50 $0.48 LOE ($/Mcfe) (3) $0.66 $0.45 $0.65 $0.41 Other expense ($/Mcfe) (4) $0.12 $0.12 $0.15 $0.09 Effect of equity hedges $1,617 $(4,492) $3,117 $(13,328) Segment - operating profit $36,559 $28,516 $69,673 $61,915 Depreciation, depletion and amortization $10,875 $7,608 $21,866 $16,029 Gas Gathering and Processing: Gas throughput volumes (MMcfd) 1,314 1,332 1,313 1,315 Average plant gas sales (MMcfd) 362 474 371 479 Average plant NGL sales (MGald) 1,378 1,358 1,388 1,376 Average gas price ($/Mcf) (5) $5.08 $4.45 $5.03 $4.74 Average NGL Price ($/Gal) (6) $0.64 $0.50 $0.63 $0.55 Gross operating margin ($/Mcf) (7) $0.53 $0.40 $0.51 $0.44 Plant operating expense ($/Mcf) (7) $0.181 $0.180 $0.175 $0.176 Effect of equity hedges $(2,470) $(2,095) $(4,739) $(8,731) Income from equity investments $1,776 $1,867 $3,702 $3,429 Segment - operating profit $41,043 $26,181 $78,792 $58,202 Depreciation, depletion and amortization $9,211 $7,583 $18,212 $15,117 Gas Transportation: Gas transportation volumes (MMcfd) 156 157 154 175 Transportation and sales revenue $5,715 $5,226 $11,454 $11,236 Operating and product purchase expense $3,186 $2,281 $6,527 $4,229 Segment - operating profit $2,529 $2,945 $4,927 $7,007 Depreciation, depletion and amortization $408 $430 $824 $862 Marketing: Average gas sales (MMcfd) 1,190 1,247 1,279 1,419 Average NGL sales (MGald) 1,643 1,625 1,627 1,639 Average gas price ($/Mcf) $5.49 $4.91 $5.40 $5.26 Average NGL price ($/Gal) $0.68 $0.55 $0.66 $0.58 Average gas sales margin ($/Mcf) $0.013 $0.062 $0.016 $0.080 Average NGL sales margin ($/Gal) $0.013 $0.012 $0.009 $0.010 Segment - operating profit $3,322 $8,807 $6,273 $23,592 Depreciation, depletion and amortization $35 $36 $52 $71 (1) Net of fuel and shrink. (2) Net of fuel, shrink, gathering and transportation. Excludes effect of hedging. (3) Includes production overhead. (4) Includes exploratory expense, delay rentals, impairment and unsuccessful well expense. (5) Represents average gas sales price adjusted for appropriate regional differential. (6) Represents average NGL sales price adjusted for appropriate transportation and fractionation charges. (7) Per Mcf of throughput. Gross operating margin is gross revenues less product purchases and joint interest and excludes effect of hedging. Table A - Q3-Q4 2004 and 2005 Equity Gas and NGL Hedges -------------------------------------------------------------------------- Hedge of Basis Product Year Quantity and Settle Price Differential -------------------------------------------------------------------------- Natural gas 2004 70,000 MMbtu per day with Mid-Continent - 55,000 a minimum price of $4.00 MMbtu per day with an and a maximum price ranging average basis price of from $6.50 to $9.45 per ($0.27) per MMbtu. MMbtu (average of $7.81 per MMbtu.) Permian - 5,000 MMbtu per day with an average basis price of ($0.34) per MMbtu. Rocky Mountain - 10,000 MMbtu per day with an average basis price of ($0.74) per MMbtu. 2005 40,000 MMbtu per day with Mid-Continent - 40,000 a minimum price of $4.50 and MMbtu per day with an a maximum price of $8.74 per average basis price of MMbtu. ($0.43) per MMbtu. -------------------------------------------------------------------------- Crude, 2004 50,000 Barrels per month Not Applicable Condensate, with a minimum price of Natural $22.00 per barrel and a Gasoline maximum price of $30.08 per barrel. 2005 25,000 Barrels per month Not Applicable with a minimum price of $30.00 per barrel and a maximum price of $42.75 per barrel. -------------------------------------------------------------------------- Propane 2004 90,000 Barrels per month Not Applicable with a minimum price of $0.42 per gallon and a maximum price of $0.56 per gallon. 2005 50,000 Barrels per month Not Applicable with a minimum price of $0.54 per gallon and an average maximum price of $0.82 per gallon. -------------------------------------------------------------------------- Ethane 2004 50,000 Barrels per month. Not Applicable Floor at $0.31 per gallon. -------------------------------------------------------------------------- DATASOURCE: Western Gas Resources, Inc. CONTACT: Investors, Ron Wirth, Director of Investor Relations, Western Gas Resources, Inc., +1-800-933-5603 or +1-303-252-6090, Web site: http://www.westerngas.com/

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