8-K 1 a2104151z8-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) February 21, 2003 (February 20, 2003)

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 net income of $50.6 million, or $1.23 per share of common stock on a fully diluted basis for the year ended December 31, 2002. This compares to net income of $95.6 million for the year ended December 31, 2001, or $2.48 per share of common stock on a fully diluted basis.

The Company also reported EBITDA (earnings before interest, taxes, depreciation and amortization) for 2002 of $184.7 million from revenues of $2.5 billion and cash flow before working capital adjustments of $161.1 million.

For the fourth quarter of 2002, the Company reported net income of $15.4 million, or $.37 per share of common stock on a fully diluted basis. This compares to net income of $10.8 million for the fourth quarter of 2001, or earnings of $.22 per share of common stock on a fully diluted basis. Earnings per share for both annual and quarterly periods give effect to preferred stock dividends.

For the fourth quarter of 2002, EBITDA was $53.4 million from revenues of $645.6 million and cash flow before working capital adjustments was $53.2 million.

Volumes and Prices. Total gas marketed, including equity gas production, gas purchased under contracts at its plants and gas purchased from third-parties for resale, averaged 2.0 billion cubic feet per day ("Bcfd") for the year ended December 31, 2002 and 1.7 Bcfd in the fourth quarter of 2002. Gas volumes marketed increased nominally in 2002 compared to 2001, but were lower in the fourth quarter of 2002 by 25 percent compared to the same period in 2001 due to a reduction in sales of third-party gas. Average gas prices for marketed volumes decreased 26 percent to $2.92 per thousand cubic feet ("Mcf") in 2002 and increased 47 percent to $3.64 per Mcf in the fourth quarter of 2002, as compared to the same periods in 2001.

Natural gas equity production in 2002 increased 34 percent to 48.9 Bcfe net compared to the same period in 2001. Production in 2002 averaged 134 million cubic feet equivalent of gas per day ("MMcfed").

Total natural gas liquids ("NGLs") marketed, including NGLs produced at the company's plants and NGLs purchased from third-parties for resale, averaged 2.0 million gallons per day ("MMGald") for the year ended December 31, 2002 and 1.8 MMGald in the fourth quarter of 2002. NGL volumes marketed decreased by 14 percent in 2002 and by 28 percent in the fourth quarter compared to the comparable periods in 2001 due to a reduction of NGLs purchased from third-parties for resale. Average NGL prices for marketed volumes decreased 14 percent to $0.42 per gallon in 2002 and increased 29 percent to $0.49 per gallon in the fourth quarter of 2002, as compared to the same periods in 2001.

Operations. The Company's fully integrated operations include exploration, production, gathering, processing, transporting and marketing of natural gas and NGLs.

Exploration and production realized operating profit (EBITDA before general and administrative expenses) of $73.7 million for 2002 compared to operating profit of $64.4 million in 2001. This increase was primarily due to significant volume growth from the Powder River Basin coal bed methane ("CBM") development and the benefit of firm transportation capacity, which allows the Company to sell gas to more favorable Mid-Continent markets.

Gathering and processing operations realized operating profit of $92.9 million for 2002 compared to operating profit of $135.8 million in 2001. The decrease in operating profit is primarily due to a reduction in product prices as gas throughput volumes were 1.2 Bcfd in 2002, comparable to 2001. An increase in gas throughput volumes in 2002 from growing gathering volumes of equity and third party CBM production was partially offset by the sale of the Toca facility in September 2002.

Gas transportation realized operating profit of $15.7 million for 2002 compared to operating profit of $16.5 million in 2001. Revenues, primarily transportation fees, in 2002 totaled $24.8 million while product purchase costs and plant operating expenses totaled $9.1 million. Gas transportation volumes on the MIGC and MGTC pipelines averaged 192 MMcfd in 2002.

Marketing realized operating profit of $37.5 million for 2002 compared to operating profit of $50.0 million in 2001. The results for the marketing business for both periods benefited from transactions utilizing the Company's firm transportation capacity and storage positions.

Hedging. Overall, in 2002, the Company's equity-hedging positions increased operating income by $20.2 million for the full year and $1.0 million for the fourth quarter. In 2001, equity hedging positions increased operating income by $11.6 million for the full year and $16.8 million for the fourth quarter.

Powder River Basin CBM. Production from the Company's jointly-owned Powder River Basin CBM development increased 33 percent in 2002 to 43.4 Bcf net. Fourth quarter volume totaled 12.3 Bcf net, including the addition of 628 MMcf for the prior period revision of third-party operated production. The Company, with its partner, continues to be the largest producer of methane in the basin. The Company participated in the drilling of 909 gross wells during 2002 in this basin.

Gas production continues to increase from the Company's Big George coal development in the Powder River Basin. As of February 17, 2002, gross production from the Company's All-Night Creek development area had increased to approximately 24 MMcfd from 88 producing wells. An additional 61 wells are in various stages of dewatering. Gas production from two additional Big George pilots has increased to a combined 3.0 MMcfd. The Company has drilled approximately 425 gross Big George CBM wells as of year-end 2002. An estimated nine industry-wide development and pilot projects in the Big George coal are now producing approximately 68 MMcfd and continue to validate the potential of the Big George coals.

The Company is the largest gatherer and transporter of methane gas in the Powder River Basin. In 2002, Western gathered 381 MMcfd of production, including third-party gas. This represents a 33 percent increase compared to 2001. Approximately 135 MMcfd of that volume was transported through the Company's MIGC pipeline.

Green River Basin. Western participated in 26 gross wells in the Pinedale Anticline during 2002 and drilled two successful wells on its acreage in the Sand Wash Basin development of northwest Colorado. Net production from these areas increased 47 percent to 5.4 Bcfe in 2002 and averaged 20 MMcfed net during the fourth quarter of 2002. Operators of wells on the Pinedale Anticline in which the Company participated during 2002 were 100 percent successful. Western plans to participate in approximately 32 wells on the Pinedale Anticline and 6 wells in the Sand Wash Basin in 2003. The Company has a large inventory of undrilled locations on the Pinedale Anticline resulting from 40-acre down spacing in this area.

Rendezvous Gas Services, L.L.C. ("Rendezvous"), a venture in which Western owns 50 percent, expanded its gathering and processing capabilities in the area during 2002. Rendezvous completed two expansion phases, which currently extend to the Jonah field area and provide 275 MMcfd of total gathering capacity. The Company expects to construct an additional 24-mile gathering line expansion northward on the Pinedale Anticline in 2003.

Balance Sheet. At December 31, 2002, Western had total assets of $1.3 billion, cash and cash equivalents in short-term investments of $7.3 million, working capital of $37.5 million, total debt outstanding of $359.9 million and a debt to capitalization ratio of 42.7 percent.

Capital Expenditures for 2003. The Company anticipates capital expenditures of approximately $182.3 million in 2003, primarily for growth and expansion projects in its Rocky Mountain upstream and midstream operations. The budget includes the previously announced acquisition of El Paso

gathering assets in Wyoming. The 2003 budget represents a 30 percent increase from the $140.6 million expended in 2002. The Rocky Mountain region will utilize 85 percent or $155.2 million of the 2003 budget. Western plans to invest approximately $68.0 million, or 37 percent of its total program, in the Powder River Basin CBM development. Approximately $55.2 million will be spent on drilling 845 gross wells and for lease acquisitions and $12.8 million for gathering and compression. Approximately half of the Powder River CBM budget is dependent on the anticipated first quarter 2003 Record of Decision for the Powder River Basin Environmental Impact Statement (EIS) and the timeliness of subsequent drilling and water discharge permits.

The Greater Green River Basin is another significant area for capital investment. Western expects to invest approximately $82.3 million, or 45 percent of the total program, in this area. The Company will spend approximately $18.4 million to participate in 38 gross wells and 3 workovers, most of which are in the rapidly developing Pinedale Anticline area, $26.9 million to expand gathering and compression services and $37.0 million for the previously announced El Paso acquisition. Exclusive of the Rocky Mountain region, the remaining $27.1 million of Western's 2003 capital spending program is expected to be spent as follows: $15.0 million for well connections, expansions, maintenance and upgrade projects in its other operating areas, $7.8 million for capitalized interest and overhead and $4.3 million for administrative expenditures.

CEO Comments. Peter Dea, Chief Executive Officer and President, stated, "The employees of Western Gas Resources are proud to deliver another strong year of financial and operational performance to our shareholders. Our solid returns and net income in 2002 reflect double-digit volume growth, cost-efficient midstream operations and our systematic price management strategy utilizing hedges and firm transportation. The balanced portfolio that has served our shareholders well these last three years, provides the foundation and catalyst for future shareholder value. The success of 2002 again confirms the quality of our large drilling inventory of low-risk, low-cost, long-lived reserves whose development is internally funded from high margin gathering, processing and marketing business segments."

Earnings Conference Call. Western invites you to participate in its fourth quarter and year-end 2002 earnings conference call today at 8:00 a.m. (Mountain Time) by dialing (719) 457-2665. 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 584702). 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 March 7, 2003.

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. 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, reserves, capital expenditures and production and sales volumes. 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, geological risk, environmental risk, weather, rig availability, transportation capacity, the ability of Western's partners to fund the necessary capital expenditures and the progress of ongoing litigation and related disputes with its co-developer in the Powder River Basin of Wyoming, 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)

		Three Months Ended December 31,						Year Ended December 31,
		2002			2001			2002			2001
Revenues:
	Sale of residue gas	$	556,917		$	498,851		$	2,123,468		$	2,849,097
	Sale of natural gas liquids		79,809			85,248			309,697			424,082
	Gathering, processing and transportation revenues		18,135			14,356			65,601			55,398
	Non-cash change in fair value of derivatives		(11,055	)		(3,382	)		(13,788	)		19,906
	Other, net		1,766			1,162			4,720			4,679

Total Revenues			645,572			596,235			2,489,698			3,353,162
Costs and expenses:
	Product purchases		554,373			521,348			2,157,179			2,986,950
	Plant and transportation operating expense		22,045			21,381			81,530			75,533
	Oil and gas exploration and production costs		9,923			3,310			34,007			27,527
	Depreciation, depletion and amortization		23,003			17,144			77,005			64,162
	Selling and administrative expense		7,189			10,533			35,828			34,272
	Loss (gain) from asset sales		304			(95	)		948			(10,748	)
	(Earnings) from equity investments		(1,660	)		(632	)		(4,453	)		(1,790	)
	Interest expense		6,663			6,177			26,951			25,130

Total costs and expenses			621,840			579,166			2,408,995			3,201,036

Income before taxes			23,732			17,069			80,703			152,126
Provision for income taxes			8,296			6,248			30,114			56,489

Net income			15,436			10,821			50,589			95,637

Preferred stock requirements			(2,808	)		(3,413	)		(9,198	)		(11,167	)

Net income available to common stock		$	12,628		$	7,408		$	41,391		$	84,470

Weighted average shares of common stock outstanding			33,044,634			32,677,061			32,952,543			32,579,813

Earnings per share of common stock		$	.38		$	.23		$	1.26		$	2.59

Weighted average shares of common stock—assuming dilution			33,689,447			33,627,161			33,607,560			37,022,369

Earnings per share of common stock—assuming dilution		$	.37	(1)	$	.22	(2)	$	1.23	(3)	$	2.48	(4)

(1): Fully diluted earnings per share for the quarter ended December 31, 2002 include, as potential common shares, the issuance of 644,813 common shares from the possible exercise of stock options.
(2): Fully diluted earnings per share for the quarter ended December 31, 2001 include, as potential common shares, the issuance of 950,100 common shares from the possible exercise of stock options.
(3): Fully diluted earnings per share for the year ended December 31, 2002 include, as potential common shares, the issuance of 655,017 common shares from the possible exercise of stock options.
(4): Fully diluted earnings per share for the year ended December 31, 2001 include, as potential common shares, the issuance of 970,858 common shares from the possible exercise of stock options and 3.5 million common shares upon conversion of the $2.625 cumulative convertible preferred stock, and also include an assumed reduction of preferred dividends of $7.2 million in determining net income attributable to common stock.

Condensed Consolidated Balance Sheet:

(Dollars in thousands)

		As of December 31,
		2002		2001
Assets:
	Current assets	$	370,248	$	365,963
	Property and equipment, net		866,646		848,307
	Other assets		65,250		53,672

Total assets			1,302,144		1,267,942

Liabilities and Stockholders' equity:
Liabilities:
	Current liabilities		332,771		305,173
	Long-term debt		359,933		366,667
	Other liabilities		126,372		122,750

Total liabilities			819,076		794,590
Stockholders' equity			483,068		473,352

Total liabilities and stockholders' equity		$	1,302,144	$	1,267,942

Reconciliation of Net Income to EBITDA:

(Dollars in thousands)

		Three Months Ended December 31,				Year Ended December 31,
		2002		2001		2002		2001
Net income		$	15,436	$	10,821	$	50,589	$	95,637
	Add:
	Depreciation, depletion and amortization		23,003		17,144		77,005		64,162
	Interest expense		6,663		6,177		26,951		25,130
	Income taxes		8,296		6,248		30,114		56,489

	EBITDA	$	53,398	$	40,390	$	184,659	$	241,418

Reconciliation of Net Income to
Cash Flow before Working Capital Adjustments:

(Dollars in thousands)

		Three Months Ended December 31,						Year Ended December 31,
		2002			2001			2002			2001
Net income		$	15,436		$	10,821		$	50,589		$	95,637
Add income items that do not affect operating cash flows:
	Depreciation, depletion and amortization		23,003			17,144			77,005			64,162
	Deferred income taxes		5,012			6,489			19,614			42,815
	Distributions less than equity income, net		(1,179	)		(942	)		(2,906	)		(29	)
	(Gain) Loss on sale of property and equipment		304			(95	)		948			(10,748	)
	Non-cash change in fair value of derivatives		11,055			3,382			13,788			(19,906	)
	Compensation expense from re-priced stock options		259			805			224			(119	)
	Foreign currency translation adjustments		(146	)		2,174			283			476
	Other non-cash items		(502	)		1,218			1,525			1,218

Cash flow before working capital adjustments		$	53,242		$	40,996		$	161,071		$	173,506

Operating Results:

(Dollars in thousands except per Mcfe, per Mcf and per Gal Amounts)

	Three Months Ended December 31,					Year Ended December 31,
	2002			2001		2002			2001
Production:
Average gas production—net volumes sold (MMcfed)		155			112		134			100
Average gas price ($/Mcfe) (1) (8)	$	2.89		$	1.85	$	2.34		$	3.16
Gathering and transportation expense ($/Mcfe) (8)	$	0.67		$	0.57	$	0.65		$	0.70
Average wellhead gas prices ($/Mcfe) (2)	$	2.22		$	1.28	$	1.69		$	2.46
Production taxes ($/Mcfe)	$	0.28		$	0.19	$	0.22		$	0.32
LOE ($/Mcfe) (3)	$	0.38		$	0.37	$	0.42		$	0.35
Other expense ($/Mcfe) (4)	$	0.05		$	0.04	$	0.08		$	0.09
Effect of equity hedges	$	2,958		$	9,453	$	25,435		$	1,486
Operating profit	$	24,459		$	16,517	$	73,734		$	64,395
Depreciation, depletion and amortization	$	12,484		$	5,098	$	28,937		$	17,692
Gas Gathering and Processing:
Gas throughput volumes (MMcfd)		1,191			1,202		1,163			1,161
Average plant gas sales (MMcfd)		457			434		447			412
Average plant NGL sales (MGald)		1,416			1,379		1,417			1,454
Average gas price ($/Mcf) (5)	$	3.14		$	1.99	$	2.47		$	3.63
Average NGL price ($/Gal) (6)	$	0.46		$	0.32	$	0.40		$	0.46
Fee revenues ($/Mcf) (7)	$	0.240		$	0.171	$	0.217		$	0.182
Gross operating margin ($/Mcf) (7)	$	0.429		$	0.333	$	0.395		$	0.454
Plant operating expenses ($/Mcf) (7)	$	0.196		$	0.174	$	0.174		$	0.162
Effect of equity hedges	$	(1,993	)	$	7,338	$	(5,242	)	$	10,146
Income from equity investments	$	1,660		$	631	$	4,453		$	1,790
Operating profit	$	25,154		$	25,515	$	92,870		$	135,834
Depreciation, depletion and amortization	$	8,473		$	10,087	$	39,792		$	39,141
Gas Transportation:
Gas transportation volumes (MMcfd)		203			193		192			193
Transportation and sales revenues	$	5,869		$	6,594	$	24,783		$	25,681
Operating and product purchase expenses	$	1,859		$	2,959	$	9,068		$	9,213
Operating profit	$	4,010		$	3,635	$	15,715		$	16,468
Depreciation, depletion and amortization	$	403		$	393	$	1,675		$	1,646
Marketing:
Average gas sales (MMcfd)		1,662			2,207		1,988			1,961
Average NGL sales (MGald)		1,761			2,450		2,010			2,347
Average gas price ($/Mcf)	$	3.64		$	2.47	$	2.92		$	3.97
Average NGL price ($/Gal)	$	0.49		$	0.38	$	0.42		$	0.49
Average gas sales margin ($/Mcf)	$	0.031		$	0.023	$	0.042		$	0.060
Average NGL sales margin ($/Gal)	$	0.006		$	0.002	$	0.008		$	0.005
Operating profit	$	6,301		$	5,576	$	37,490		$	50,030
Depreciation, depletion and amortization	$	36		$	40	$	157		$	161

(1): Net of fuel and shrink.
(2): Net of fuel, shrink, gathering and transportation. Excludes effect of hedging.

(3): Includes production overhead.
(4): Includes 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.
(8): The per unit statistics for the three months ended December 31, 2001 exclude the effect of a $2.9 million reclassification adjustment.

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: February 21, 2003		By:		/s/ WILLIAM J. KRYSIAK William J. Krysiak Executive Vice President/Chief Financial Officer (Principal Financial and Accounting Officer)

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ITEM 9. REGULATION FD DISCLOSURE

SIGNATURES