QuickLinks -- Click here to rapidly navigate through this document

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)	May 8, 2003
	(May 8, 2003)

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

Delaware	1-10389	84-1127613
(State or other jurisdiction of incorporation)	(Commission File Number)	(I.R.S. Employer Identification No.)
1099 18th Street, Suite 1200	Denver, Colorado	80202
(Address of principal executive offices)		(Zip Code)
(303) 452-5603 (Registrant's telephone number, including area code)
12200 North Pecos	Denver, Colorado	80234
(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. ("Western") (NYSE:WGR) today announced net income of $23.4 million or $0.63 per share of common stock for the quarter ended March 31, 2003. This compares to net income of $8.0 million or $0.18 per share of common stock for the same period in 2002. Earnings per share are presented on a fully-diluted basis for both periods and are after giving effect to preferred stock dividends.

        The Company also reported EBITDA (earnings before interest, taxes, depreciation and amortization and the cumulative effect of a change in accounting principle) for the first quarter of 2003 of $72.8 million and cash flow before working capital adjustments of $72.1 million. Revenues totaled $888.1 million.

        Cumulative Effect of a Change in Accounting Principle.    In June 2001, the Financial Accounting Standards Board, issued SFAS No. 143, "Accounting for Asset Retirement Obligations" ("SFAS No. 143"). SFAS No. 143 establishes accounting standards for recognition and measurement of a liability for an asset retirement obligation and the associated asset retirement cost. The Company adopted SFAS No. 143 on January 1, 2003. The adoption of SFAS No. 143 resulted in a one-time after-tax charge to earnings of $6.7 million or $0.18 per share of common stock on a fully diluted basis in the first quarter of 2003 for the cumulative effect of the change in accounting principle. Net income before the cumulative effect of the change in accounting principle was $30.1 million, or $0.81 per share of common stock on a fully diluted basis for the first quarter of 2003.

        Volumes and prices.    Natural gas production and total gas sales volumes marketed in the first quarter of 2003 increased sharply compared to the same period a year ago.

        Natural gas equity production increased 21 percent to 13.2 billion cubic feet equivalent ("Bcfe") compared to the first quarter of 2002 and averaged 147 million cubic feet equivalent per day ("MMcfed"). All of the Company's production was achieved in the Powder River Basin coal bed methane ("CBM") play and the Greater Green River Basin.

        Total gas sales volumes marketed, including equity gas production, gas purchased under contracts at the Company's plants and gas purchased from third parties for resale, averaged 1.6 billion cubic feet per day ("Bcfd") in the first quarter of 2003. This represents a decrease of 35 percent as compared to 2002 due to a reduction of third-party gas sales. Average gas prices for marketed volumes increased 120 percent to $5.44 per Mcf compared to $2.47 per Mcf for the same period in 2002.

        Total natural gas liquids ("NGLs") sales volumes marketed averaged 1.7 million gallons per day in the first quarter of 2003. This represents a decrease of 15 percent as compared to the same period in 2002, which was largely the result of the Company's sale of its Toca facility in September 2002. Average NGL prices for marketed volumes increased 68 percent to $0.62 per gallon compared to $0.37 per gallon in the same period in 2002.

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

        Exploration and production realized operating profit (EBITDA before general and administrative expenses) of $33.3 million for the first quarter of 2003 compared to $14.9 million for the first quarter of 2002. This increase was primarily due to substantially higher natural gas prices, significant volume growth from the 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 $31.8 million for the first quarter of 2003 compared to $18.8 million for the first quarter of 2002. The increase is primarily due to higher commodity prices and increased gathering volumes from equity and third-party CBM production and the acquisition of several gathering systems in January 2003.

        Gas transportation realized operating profit of $4.0 million for the first quarter of 2003 compared to $4.3 million for the first quarter of 2002. The transportation segment includes the results from the MIGC and MGTC pipelines in the Powder River Basin.

        Marketing realized operating profit of $15.0 million for the first quarter of 2003 compared to $8.0 million for the same period in 2002. The results for the marketing business benefited significantly from transactions utilizing the Company's firm transportation and storage capacity.

        Hedging.    The Company's equity hedging positions decreased operating profit by $15.5 million for the first quarter of 2003, including losses of $2.8 million from the discontinuance of certain equity hedges and increased operating profit by $9.5 million in the first quarter of 2002.

        Powder River Basin CBM.    Net CBM production volumes increased 17 percent to 11.2 Bcf in the first quarter of 2003 as compared to the same period in 2002 and averaged 124 MMcfd. The Company, with its partner, continues to be the largest producer of methane in the basin. Western currently plans to participate in over 800 wells in the Powder River Basin in 2003, of which 101 wells were drilled in the first quarter. Completion of the Company's 2003 drilling program will be subject to obtaining the necessary drilling and water discharge permits in a timely fashion.

        On April 30, 2003, gross CBM production from wells in which the Company has an interest in the Big George coal was approximately 30 MMcfd from one development and two pilot areas. In total, approximately 440 Big George wells have been drilled through March 31, 2003. The Company expects to drill approximately 400 gross wells in various pilots in the Big George coal during 2003. Industry, including Western, was producing over 80 MMcfd in February 2003 from the Big George in eight pilots over a 40-mile area.

        Western averaged 416 MMcfd of CBM gathering volumes, including third-party gas, during the first quarter of 2003. This represents a 20 percent increase compared to the same period in 2002. Of that volume, approximately 128 MMcfd was transported through the Company's MIGC pipeline. The Company remains the largest gatherer and transporter of CBM in the Powder River Basin.

        The Bureau of Land Management's Buffalo, Wyoming field office issued the final Record of Decision ("ROD") for the Powder River Basin Oil and Gas Environmental Impact Statement ("EIS") on April 30, 2003. The Company is currently in the process of reviewing the ROD to determine its impact on its operations in this area. Based on Western's preliminary review of the final EIS, water discharge and air quality guidelines are, for the most part consistent with recent industry practices. More planning will be required for permitting related to certain plant and animal species and cultural surveys and noxious weed mitigation.

        Greater Green River Basin.    Production from the Pinedale Anticline and Jonah Field development areas of southwest Wyoming and the Sand Wash Basin development area in northwest Colorado increased 50 percent to 2.0 Bcfe net in the first quarter of 2003 compared to the same period of 2002. In 2003, Western plans to participate in approximately 60 wells on the Pinedale Anticline, of which five were drilled in the first quarter, and six wells in the Sand Wash Basin, of which one was drilled in the first quarter. The Company has exposure to participate in up to 500 gross (55 net) potential drilling locations on the Pinedale Anticline based on 40-acre spacing in this area.

        Balance sheet.    At March 31, 2003, Western had total assets of $1.5 billion, total debt outstanding of $309.8 million and a debt to capitalization ratio of 38 percent.

        CEO comments.    Peter Dea, Chief Executive Officer and President, commented, "The first quarter of 2003 was extremely profitable, particularly as a result of strong commodity prices, continued growth in production and gathering volumes and benefits of our firm transportation position to the Mid-Continent markets. The issuance of the final Record of Decision for drilling on federal lands in the Powder River Basin is a tremendous step towards the full develop of this play and we will begin to realize its enormous potential during the next several years."

        Revisions to operational performance guidance for the remainder of 2003.    The Company provided operational performance guidelines for 2003 in a press release dated February 20, 2003. The following information represents modifications to the previous guidance.

        In connection with the adoption of SFAS No. 143, the Company completed a review of its operating assets and reevaluated the operating life and salvage values of the associated equipment. As a result, depreciation, depletion and amortization was $2.5 million less than our original guidance. The Company expects the decreased rate of depreciation, depletion and amortization to continue in future quarters and will total approximately $57.4 million for the remaining nine months of 2003 as follows: 53 percent for gathering and processing, 39 percent for exploration and production, one percent for transportation and seven percent for marketing and corporate. Selling and administrative expense for the remaining nine months of 2003 is expected to be approximately $26.5 million. Interest expense is expected to be approximately $20 million for the remainder of 2003.

        Western's equity hedges and the associated basis positions for its equity volumes of natural gas and NGLs are outlined under Table A. For the remainder of 2003, Western has hedged approximately 51 percent of its projected equity natural gas volumes and approximately 77 percent of its estimated equity volumes of crude and NGLs. In order to determine the hedged gas price to the particular operating region, adjust the NYMEX—equivalent price for the basis differential. The NYMEX or Mt. Belvieu—equivalent prices for NGLs do not include the cost of the hedges of approximately $698,000. There is no associated cost for the natural gas hedges. The natural gas equity hedges associated with the Permian differential and all NGL equity hedges are related to the gathering and processing business. The remaining natural gas hedges are related to the exploration and production business.

        Earnings conference call.    Western invites you to participate in its first quarter 2003 earnings conference call today at 8:00 AM Mountain Time by dialing (913) 981-5532. A replay of the conference call will be available through midnight, May 15, by dialing (719) 457-0820 (passcode 667947). An audio playback will also be available on Western's Web site after 10:00 AM Mountain Time today at www.westerngas.com. This call can be accessed by selecting Financial/Investor Information then the Current News option on the menu. The audio replay will be available on the web site through May 31, 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, 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.

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

Financial Results:
(In thousands except share and per share amounts)

			Three Months Ended March 31,
			2003			2002
Revenues:
	Sale of residue gas		$	779,739		$	545,589
	Sale of natural gas liquids			92,049			64,807
	Gathering, processing and transportation revenues			19,777			15,431
	Non-cash change in fair value of derivatives			(4,163	)		(10,995	)
	Other, net			704			1,083
		Total Revenues		888,106			615,915
Costs and expenses:
Product purchases				771,602			544,606
Plant and transportation
operating expense				21,922			18,871
Oil and gas exploration and production costs				12,511			7,389
Depreciation, depletion and amortization				18,143			17,946
Selling and administrative expense				10,592			8,691
Loss from asset sales				281			9
(Earnings) from equity investments				(1,562	)		(851	)
	Interest expense			6,814			6,660
	Total costs and expenses			840,303			603,321
Income before taxes				47,803			12,594
Provision for income taxes				17,704			4,594
Net income before cumulative effect of change in accounting principle				30,099			8,000
Cumulative effect of change in accounting principle				(6,724	)		—
Net income				23,375			8,000
Preferred stock requirements				(1,811	)		(2,130	)
Net income available to common stock			$	21,564		$	5,870
Weighted average shares of common stock outstanding				33,087,680			32,760,081
Earnings per share of common stock			$	.65		$	.18
Weighted average shares of common stock—assuming dilution				37,163,098			33,457,239
Earnings per share of common stock—assuming dilution			$	.63	(1)	$	.18	(2)

(1)

Fully-diluted earnings per share for the quarter ended March 31, 2003 include, as potential common shares, the issuance of 603,719 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 $1.8 million in determining net income attributable to common stock.

(2)

Fully-diluted earnings per share for the quarter ended March 31, 2002 include, as potential common shares, the issuance of 697,158 common shares from the possible exercise of stock options.

Condensed Consolidated Balance Sheet:
(Dollars in thousands)

		As of March 31, 2003		As of December 31, 2002
Assets:
	Current assets	$	497,148	$	370,248
	Property and equipment, net		911,572		866,646
	Other assets		63,870		65,250
Total assets		$	1,472,590	$	1,302,144
Liabilities and Stockholders' equity:
Liabilities:
	Current liabilities	$	507,075	$	332,771
	Long-term debt		309,833		359,933
	Other liabilities		155,624		126,372
Total liabilities			972,532		819,076
Stockholders' equity			500,058		483,068
Total liabilities and stockholders' equity		$	1,472,590	$	1,302,144

Reconciliation of Net Income to EBITDA:
(Dollars in thousands)

		Three months Ended March 31
		2003		2002
Net income		$	23,375	$	8,000
Add:
	Cumulative effect of change in accounting principle		6,724		—
	Depreciation, depletion and amortization		18,143		17,946
	Interest Expense		6,814		6,660
	Income taxes		17,704		4,594
	EBITDA	$	72,760	$	37,200

Reconciliation of Net Income to
Cash Flow before Working Capital Adjustments:
(Dollars in thousands)

		Three months Ended March 31,
		2003		2002
Net income		$	23,375	$	8,000
Add income items that do not affect operating cash flows:
	Depreciation, depletion and amortization		18,143		17,946
	Deferred income taxes		17,183		3,836
	Distributions less than equity income, net		1,431		(598	)
	Loss on sale of property and equipment		281		9
	Non-cash change in fair value of derivatives		4,163		10,995
	Compensation expense from re-priced stock options		53		312
	Foreign currency translation adjustments		—		183
	Cumulative effect of change in accounting principle		6,724		—
Other non-cash items			724		76
Cash flow before working capital adjustments		$	72,077	$	40,759

Operating Results:
(Dollars in thousands except per Mcfe, per Mcf and per Gal amounts)

	Three Months Ended March 31,
	2003			2002
Production:
Average gas production—net volumes sold (MMcfed)		147			121
Average gas price ($/Mcfe)(1)	$	4.87		$	1.85
Gathering and transportation expense ($/Mcfe)	$	0.72		$	0.57
Average wellhead gas prices ($/Mcfe)(2)	$	4.15		$	1.28
Production taxes ($/Mcfe)	$	0.57		$	0.17
LOE ($/Mcfe)(3)	$	0.36		$	0.38
Other expense ($/Mcfe)(4)	$	0.05		$	0.11
Effect of equity hedges	$	(8,889	)	$	8,241
Operating profit	$	33,276		$	14,851
Depreciation, depletion and amortization	$	8,060		$	5,321
Selling and administrative expense	$	3,241		$	2,364
Gas Gathering and Processing:
Gas Throughput Volumes (MMcfd)		1,296			1,181
Average Plant Gas Sales (MMcfd)		476			443
Average Plant NGL Sales (MGald)		1,394			1,246
Average gas price ($/Mcf)(5)	$	5.10		$	1.97
Average NGL price ($/Gal)(6)	$	0.59		$	0.34
Fee revenue ($/Mcf)(7)	$	0.240		$	0.192
Gross operating margin ($/Mcf)(7)	$	0.487		$	0.313
Plant operating expense ($/Mcf)(7)	$	0.171		$	0.154
Effect of equity hedges	$	(6,584	)	$	1,056
Income from equity investments	$	1,562		$	851
Operating profit	$	31,837		$	18,782
Depreciation, depletion and amortization	$	7,895		$	10,596
Selling and administrative expense	$	4,735		$	3,841
Gas Transportation:
Gas transportation volumes (MMcfd)		193			196
Transportation and sales revenues	$	6,011		$	6,920
Operating and product purchase expenses	$	1,965		$	2,615
Operating profit	$	4,046		$	4,305
Depreciation, depletion and amortization	$	433		$	435
Selling and administrative expense	$	561		$	713
Marketing:
Average gas sales (MMcfd)		1,593			2,443
Average NGL sales (MGald)		1,655			1,943
Average gas price ($/Mcf)	$	5.44		$	2.47
Average NGL price ($/Gal)	$	0.62		$	0.37
Average gas sales margin ($/Mcf)	$	0.095		$	0.024
Average NGL sales margin ($/Gal)	$	0.008		$	0.011
Operating profit	$	15,031		$	7,971
Depreciation, depletion and amortization	$	35		$	40
Selling and administrative expense	$	2,055		$	1,773

(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.

Table A—Q2-Q4-2003 Equity Gas and NGL Hedges

Product	Quantity and Settle Price	Hedge of Basis Differential
Natural gas	50,000 MMbtu per day with an average price of $3.94 per MMbtu.	Mid-Continent—22,000 MMbtu per day average with an average basis price of ($0.16) 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. (all related to Mid-Continent volumes)	Permian—5,000 MMbtu per day with an average basis price of ($0.13) per MMbtu.
		Rocky Mountain—43,000 MMbtu per day average with an average basis price of ($0.79) per MMbtu.
Crude, Condensate, Natural Gasoline	55,000 Barrels per month at an average price of $24.97 per barrel.	Not Applicable
Butanes	50,000 Barrels per month. Floor at $24.00 per barrel. (Crude oil used as surrogate for butanes.)	Not Applicable
Propane	100,000 Barrels per month. Average minimum and maximum price of $0.37 per gallon and $0.50 per gallon, respectively.	Not Applicable
Ethane	81,000 Barrels per month. Average minimum and maximum price of $0.25 per gallon and $0.37 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: May 8, 2003	By:	/s/  WILLIAM J. KRYSIAK William J. Krysiak Executive Vice President, Chief Financial Officer (Principal Financial and Accounting Officer)

QuickLinks

ITEM 9. REGULATION FD DISCLOSURE

SIGNATURES