8-K 1 a2093696z8-k.htm 8-K
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported) November 13, 2002 (November 12, 2002)

WESTERN GAS RESOURCES, INC.
(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation)		1-10389 (Commission File Number)		84-1127613 (I.R.S. Employer 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 or former address, if changed since last report).

ITEM 9. REGULATION FD DISCLOSURE

The following information is furnished pursuant to Regulation FD, Rules 100-103:

Western Gas Resources, Inc. (NYSE:WGR) today announced that, for the quarter ended September 30, 2002, it had net income of $13.4 million, or $0.34 per share of common stock on a fully diluted basis. This compares to net income of $14.8 million for the same period in 2001, or $0.36 per share of common stock on a fully diluted basis. Earnings per share for both periods are after the requirements for preferred dividends.

For the third quarter of 2002, EBITDA (earnings before interest, taxes, depreciation and amortization) was $48.3 million from revenues of $615.2 million, net cash provided by operating activities was $4.6 million and cash flow from operations (net cash provided by operating activities before adjustments for working capital) was $37.9 million.

For the nine months ended September 30, 2002, net income was $35.2 million, or $0.86 per share of common stock on a fully diluted basis. This compares to net income of $84.8 million for the same period in 2001, or $2.23 per share of common stock on a fully diluted basis. Earnings per share for both periods are after the requirements for preferred dividends.

For the nine months ended September 30, 2002, EBITDA was $131.3 million, net cash provided by operating activities was $72.9 million, cash flow from operations was $107.8 million and revenues were $1.8 billion.

Recurring earnings, which are calculated by deducting from net income the after-tax effect of gains and losses from asset sales, were $13.7 million for the third quarter of 2002 and $35.6 million for the nine months ended September 30, 2002. This compares to recurring earnings of $15.1 million and $78.1 million for the same periods in 2001.

Total gas sales volumes marketed, including equity gas production, gas produced at the Company's plants and gas purchased from third parties for resale, averaged 2.0 billion cubic feet per day (Bcfd) in the third quarter of 2002. Average gas prices for marketed volumes were $2.77 per Mcf. Gas volumes marketed decreased as a result of fewer sales of gas purchased from third parties for resale.

Total NGL sales volumes marketed, including NGLs produced at the Company's plants and NGLs purchased from third parties for resale, averaged 2.2 million gallons per day (MMGald) in the third quarter of 2002. Average NGL prices for marketed volumes were $0.42 per gallon. NGL volumes marketed decreased as a result of fewer sales of NGLs purchased from third parties for resale.

Operations. The Company's fully integrated operations include exploration and production, gathering and processing, gas transportation and marketing.

Exploration and production realized operating income (EBITDA before general and administrative expenses) of $10.6 million for the third quarter of 2002 compared to $6.2 million for the same period in 2001. This increase was due to significant volume growth from the Powder River Basin CBM development and higher gas prices resulting from firm transportation capacity to more favorable Mid-Continent gas markets. Natural gas equity production in the third quarter of 2002 increased 41 percent compared to the same period in 2001, averaging 139 million cubic feet equivalent per day (MMcfed). All of the Company's production growth was achieved organically through the drill bit in the Powder River Basin coal bed methane (CBM) play and the Greater Green River Basin. Average gas prices realized at the wellhead, net of fuel, shrink, gathering and transportation, were $1.41 per Mcf before the benefit of equity hedging.

Gathering and processing realized operating income of $25.5 million for the third quarter of 2002 compared to $25.7 million for the third quarter of 2002. Gas throughput volumes in the third quarter of 2002 increased eight percent compared to the same period in 2001 to 1.2 Bcfd. The increase in gas throughput volumes was largely a result of increased gathering volumes of equity and third party CBM production from the Powder River Basin. Plant gas sales averaged 445 MMcfd at a realized price of $2.27 per Mcf. Plant NGL sales averaged 1.5 MMGald at a realized price of $0.40 per gallon. These

prices do not reflect the effect of equity hedging. The Company continues to connect third-party wells to maintain stable gathering volumes against normal field declines.

Gas transportation realized operating income of $3.0 million in both the third quarter of 2002 and 2001. Gas transportation volumes in the third quarter of 2002 were 182 MMcfd.

Marketing realized operating income of $9.7 million for the third quarter of 2002 compared to operating income of $8.9 million for the same period in 2001. The results for the marketing business for both periods benefited from transactions utilizing the Company's firm transportation capacity where regional differentials widened and its storage positions.

Powder River Basin Coal Bed Methane. Net CBM production volumes in the Powder River Basin development increased 40 percent to approximately 123 MMcfd in the third quarter of 2002 as compared to the same period in 2001. As of September 30, 2002, net CBM production was approximately 128 MMcfd. By year-end, the Company expects net CBM production volumes to show an approximate 30 percent increase in 2002 compared to 2001. Through October 31, 2002, the Company has participated in the drilling of 865 gross CBM wells and expects to participate in the drilling of over 900 wells by year-end. In 2003, the Company expects to continue its aggressive development program and participate in the drilling of approximately 800 gross wells on its 515,000 net acre leasehold in the play. Approximately one-half of the 800-well drilling program is independent of an Environmental Impact Statement (EIS), which is expected to be completed in the first quarter of 2003.

CBM gas production from the Company's All Night Creek development area in the Big George coal of the Powder River Basin development has increased approximately 225 percent from a year ago to approximately 13.5 MMcfd gross as of October 31, 2002. Eighty-two wells are currently producing and 94 wells are dewatering or awaiting connection. In addition, the Company's Pleasantville pilot in the Big George is now producing 700 Mcfd. Industry-wide Big George production has seen a 200 percent growth rate in the last 12 months to approximately 42 MMcfd.

Green River Basin. In the Green River Basin of Wyoming, the Company holds approximately 32,500 net acres, or 203,000 gross acres, largely concentrated in the very active Pinedale Anticline/Jonah Field area. The Company will participate in 26 gross wells in 2002 and plans to participate in a comparable drilling program in 2003. Net production from the area averaged 12.5 MMcfed in the third quarter.

Hedging. In the third quarter of 2002, the Company's equity-hedging positions increased operating income by $6.9 million as compared to an increase of $10.6 million in the third quarter of 2001. For the fourth quarter of 2002, the Company has hedged approximately 60 percent and 68 percent of its estimated equity gas and equity NGL volumes respectively at NYMEX or Mt. Belvieu-equivalent prices as outlined in Table A below.

For 2003, the Company has hedged approximately 51 percent and 36 percent of its estimated equity gas and NGL volumes respectively at NYMEX or Mt. Belvieu-equivalent prices as outlined in Table B below.

Balance Sheet. At September 30, 2002, Western had total assets of $1.3 billion, cash and cash equivalents in short-term investments of $6.4 million, total debt outstanding of $357.2 million and a debt to capitalization ratio of 42 percent.

CEO Comments. Chief Executive Officer and President Peter A. Dea commented, "We were very pleased with our performance in the third quarter. Our equity hedging program and firm transportation agreements provided by our marketing department insulated us from the weak Rocky Mountain natural gas prices and improved netbacks in our production business by approximately $1.18 per Mcf. We also remain on target to grow production 30 percent on a year-over-year basis as we continue to drill into our existing leasehold and deliver value to our stockholders.

"The nearly 100 percent success of our drilling program for 2001 and 2002 confirms the long-term value to our shareholders of our 10-year drilling inventory of similar low-risk, low-cost and high-return reserves. Low finding and development costs of approximately $0.50 per Mcf for both plays combined further complement the low-risk long-lived reserves in the Powder River Basin CBM and Pinedale Anticline developments.

"Furthermore, the high-graded gathering and processing facilities continue to provide a solid foundation, providing stable income and cash flow to internally fund our growth projects. Overall, the fully integrated nature of our focused natural gas strategy provided solid income for another consecutive quarter."

Operational performance guidance for the remainder of 2002. Operational performance guidelines for 2002 were provided in a press release by the Company dated February 28, 2002 and updated May 15, 2002 and August 13, 2002. The following information represents modifications to the previous guidance.

Production. Production volumes are expected to average 142 MMcfed net for the fourth quarter of 2002. This includes 125 MMcfd of CBM production in the Powder River Basin and 17 MMcfed from the Greater Green River Basin. The Company anticipates selling approximately 65 to 70 percent of its production in the Mid-Continent market centers and 30 to 35 percent in the Rocky Mountain market centers. This does not reflect the benefit of equity hedges, which effectively reduces the Company's exposure to Rockies' pricing to approximately eight percent of its production. Gathering and transportation costs, including firm transportation costs associated with equity production volumes, are expected to average $0.70 per Mcf. LOE for all production is expected to average approximately $0.45 per Mcf. This includes production overhead of $0.09 per Mcf and other miscellaneous expenses of $0.06 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 fourth quarter of 2002 are expected to average 1,125 MMcfd. Natural gas plant sales volumes are expected to average 475 MMcfd and NGL plant sales volumes are expected to average 1.4 MMGald. The gross operating margin (gross revenues less product purchase expenses) for the gathering and processing business is expected to average approximately $0.39 per Mcf of facility throughput. Gross operating margin is dependent on commodity prices, and these estimates are based on an assumption of $3.25 per Mcf for natural gas and $25.60 per barrel for crude oil (NYMEX-equivalent prices.) Plant operating expenses are expected to average $0.17 per Mcf of throughput.

Marketing. Marketed natural gas volumes (which include production, plant and third-party gas) are expected to be approximately 2.0 Bcfd for the fourth quarter of 2002. Gas marketing margins are expected to be approximately $0.01 per Mcf. Marketed NGL volumes, including plant and third party volumes, are expected to be approximately 2.0 MMGald. NGL marketing margins are expected to be approximately $0.005 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 approximately $8.0 million for the fourth quarter of 2002 and interest expenses are estimated to be approximately $7.0 million. The tax rate is expected to be 37.4 percent.

Earnings Conference Call. Western invites you to participate in its third quarter 2002 earnings conference call today at 8:00 a.m. (Mountain Time) by dialing (719) 457-2661. Please dial in five to ten minutes before the start of the call. A replay of the conference call will be available after 10:00 a.m. (Mountain Time) today for one week following the call by dialing (719) 457-0820 (passcode 526178). The live conference call may also be accessed on the Internet by logging onto Western's Web site at 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 November 30, 2002.

Company Description. Western is an independent natural gas 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. 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 www.westerngas.com.

This press release contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 regarding future drilling activity,production and sales volumes, margins and expenses. 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 prices, government regulation or action, litigation, environmental 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.

Investor Contact:

Ron Wirth, Director of Investor Relations
(800) 933-5603
e-mail: rwirth@westerngas.com

		Quarter Ended September 30						Nine Months Ended September 30
		2002			2001			2002			2001
*Financial Results:* ($000s except share and per share amounts)
Revenues		$	615,223		$	673,785		$	1,846,919		$	2,758,085
Costs and expenses:
	Product purchases		529,911			594,452			1,602,806			2,465,602
	Plant operating expense		20,824			18,875			59,485			54,152
	Oil and gas exploration and production costs		7,553			5,514			24,084			24,217
	Depreciation, depletion and amortization		18,813			17,257			54,002			47,018
	Selling and administrative expense		8,061			7,715			28,639			23,739
	Loss (gain) from asset sales		562			570			644			(10,653	)
	Interest expense		6,858			6,132			20,288			18,953

Total costs and expenses			592,582			650,515			1,789,948			2,623,028

Income before taxes			22,641			23,270			56,971			135,057
Provision for income taxes			9,254			8,497			21,818			50,241

Net income			13,387			14,773			35,153			84,816

Preferred stock requirements			(2,130	)		(2,584	)		(6,390	)		(7,753	)

Net income available to common stock		$	11,257		$	12,189		$	28,763		$	77,063

Weighted average shares of common stock outstanding			33,010,914			32,657,637			32,921,846			32,547,397
Earnings per share of common stock		$	0.34		$	0.37		$	0.87		$	2.37
Weighted average shares of common stock—assuming dilution			33,589,743			33,572,836			33,580,658			36,992,899
Earnings per share of common stock—assuming dilution		$	0.34	(1)	$	0.36	(2)	$	0.86	(3)	$	2.23	(4)
Net cash provided by operating activities		$	4,627		$	6,241		$	72,865		$	144,539
Cash flow from operations (5)		$	37,895		$	17,725		$	107,828		$	132,509
EBITDA		$	48,312		$	46,659		$	131,261		$	201,028

(1): Fully diluted earnings per share for the quarter ended September 30, 2002 include, as potential common shares, the issuance of 578,829 common shares from the possible exercise of stock options.
(2): Fully diluted earnings per share for the quarter ended September 30, 2001 include, as potential common shares, the issuance of 915,199 common shares from the possible exercise of stock options.
(3): Fully diluted earnings per share for the nine months ended September 30, 2002 include, as potential common shares, the issuance of 658,812 common shares from the possible exercise of stock options.
(4): Fully diluted earnings per share for the nine months ended September 30, 2001 include, as potential common shares, the issuance of 973,804 common shares from the possible exercise of stock options and 3.5 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 $5.4 million in determining net income attributable to common stock. The conversion of the preferred stock has not actually occurred.
(5): Represents net cash provided by operating activities before working capital adjustments.

	Quarter Ended September 30				Nine Months Ended September 30
	2002		2001		2002		2001
*Operating Results:*
Production:
Gas Production—Net Volumes Sold (MMcfed)		139		99		127		96
Average Wellhead Gas Prices ($/Mcf)(1)	$	1.41	$	1.22	$	1.45	$	2.95
Production Taxes ($/ Mcf)	$	0.19	$	0.20	$	0.20	$	0.38
LOE ($/ Mcf)(2)	$	0.41	$	0.33	$	0.44	$	0.35
Other Expenses ($/Mcf)(3)	$	0.04	$	0.08	$	0.10		0.11
Gas Gathering and Processing:
Gas Throughput Volumes (MMcfd)		1,227		1,141		1,184		1,147
Average Plant Gas Sales (MMcfd)		445		410		445		405
Average Plant NGL Sales (MGald)		1,515		1,480		1,420		1,480
Average Gas Prices ($/Mcf)(4)	$	2.27	$	2.39	$	2.34	$	4.35
Average NGL Prices ($/Gal)(5)	$	0.40	$	0.39	$	0.37	$	0.49
Fee Revenues ($/Mcf)(6)	$	0.22	$	0.18	$	0.21	$	0.19
Gross Operating Margin ($/Mcf)(6)	$	0.38	$	0.40	$	0.38	$	0.49
Plant Operating Expenses ($/Mcf)(6)	$	0.15	$	0.16	$	0.16	$	0.16
Gas Transportation:
Gas Transportation Volumes (MMcfd)		182		187		188		191
Marketing:
Average Gas Sales (MMcfd)		2,000		2,130		2,100		1,880
Average NGL Sales (MGald)		2,220		2,335		2,100		2,315
Average Gas Prices ($/Mcf)	$	2.77	$	2.77	$	2.73	$	4.57
Average NGL Prices ($/Gal)	$	0.42	$	0.44	$	0.40	$	0.53
Average Gas Sales Margin ($/Mcf)	$	0.04	$	0.04	$	0.05	$	0.09
Average NGL Sales Margin ($/Gal)	$	0.009	$	0.003	$	0.008	$	.006

(1): Net of fuel, shrink, gathering and transportation. Excludes hedging.
(2): Includes production overhead.
(3): Includes delay rentals, impairments and unsuccessful well expense.
(4): Represents average sales price adjusted for appropriate locational differential.
(5): Represents average sales price adjusted for appropriate transportation and fractionation charges.
(6): Per Mcf of throughput. Gross operating margin is gross revenues less product purchases and joint interest.

Table A—Outstanding Equity Hedge Positions and the Associated Basis for the Remainder of 2002. In order to determine the hedged price to the particular operating region, deduct the basis differential from the NYMEX price. The prices for NGLs do not include the cost of the hedges of approximately $1.5 million. There is no associated cost for the natural gas hedges.

Product	Quantity and Settle Price	Hedge of Basis Differential
Natural gas	80,000 MMbtu per day with an average minimum and maximum price of $3.81 and $5.87 per MMbtu, respectively.	Mid-Continent—40,000 MMbtu per day with an average basis price of ($0.14) per MMbtu.
		Permian—15,000 MMbtu per day with an average basis price of ($0.05) per MMbtu.
		Rocky Mountain — 25,000 MMbtu per day with an average basis price of ($0.51) per MMbtu.
Crude, Condensate, Natural Gasoline and Butanes	75,000 Barrels per month. Fixed price of $20.20 per barrel with right to participate in price increases above $22.50 per barrel.	Not Applicable
	55,000 Barrels per month. Floor at $20.00 per barrel.
Propane	120,000 Barrels per month. Floor at $0.32 per gallon.	Not Applicable
Ethane	50,000 Barrels per month. Floor at $0.21 per gallon.
	20,000 Barrels per month. Sold at $0.21 per gallon with right to participate in price increases above $0.25 per gallon.	Not Applicable

Table B—Outstanding Equity Hedge Positions and the Associated Basis for 2003. In order to determine the hedged price to the particular operating region, deduct the basis differential from the NYMEX price. The NYMEX prices for NGLs do not include the cost of the hedges of approximately $930,000. There is no associated cost for the natural gas hedges.

Product	Quantity and Settle Price	Hedge of Basis Differential
Natural gas	60,000 MMbtu per day with an average price of $3.95 per MMbtu.	Mid-Continent—20,000 MMbtu per day with an average basis price of ($0.15) per MMbtu.
	20,000 MMbtu per day with a minimum price of $3.50 per MMbtu and an average maximum price of $4.43 per MMbtu.	Permian—5,000 MMbtu per day with an average basis price of ($0.13) per MMbtu.
		Rocky Mountain—55,000 MMbtu per day with an average basis price of ($0.80) per MMbtu.
Crude, Condensate, Natural Gasoline and Butanes	50,000 Barrels per month. Floor at $24.00 per barrel. (Crude oil used as surrogate for butanes.)	Not Applicable
Propane	50,000 Barrels per month. Average minimum and maximum price of $0.37 per gallon and $0.525 per gallon, respectively.	Not Applicable
Ethane	75,000 Barrels per month. Average minimum and maximum price of $0.253 per gallon and $0.373 per gallon, respectively.	Not Applicable

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: November 13, 2002	By:	/s/ WILLIAM J. KRYSIAK William J. Krysiak Executive Vice-President, Chief Financial Officer (Principal Financial and Accounting Officer)

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: November 13, 2002	By:

		William J. Krysiak Executive Vice-President, Chief Financial Officer (Principal Financial and Accounting Officer)

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ITEM 9. REGULATION FD DISCLOSURE

SIGNATURES