WESTERN GAS RESOURCES INC - 10-K Annual Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K
(Mark One)

[X] Annual report pursuant to section 13 or 15(d) of the Securities Exchange
Act of 1934 for the fiscal year ended December 31, 1997 or

[ ] Transition report pursuant to section 13 or 15(d) of the Securities
Exchange Act of 1934 [No Fee Required] for the transition period from
_________________ to _________________

Commission file number 1-10389
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WESTERN GAS RESOURCES, INC.
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(Exact name of registrant as specified in its charter)

Delaware 84-1127613
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

12200 N. Pecos Street, Denver, Colorado 80234-3439
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(Address of principal executive offices) (Zip Code)

(303) 452-5603
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Registrant's telephone number, including area code

No Changes
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(Former name, former address and former fiscal year, if changed since last
report)

Title of each class Name of exchange on which registered
------------------- ------------------------------------
Common Stock, $0.10 par value New York Stock Exchange

$2.28 Cumulative Preferred Stock,
$0.10 par value New York Stock Exchange

$2.625 Cumulative Convertible
Preferred Stock, $0.10 par value New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
----- -----

The aggregate market value of voting common stock held by non-affiliates of the
registrant on February 27, 1998 was $338,659,119.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Part III of this Report (Items 10, 11, 12 and 13) is
incorporated by reference from the registrant's proxy statement to be filed
pursuant to Regulation 14A with respect to the annual meeting of stockholders
scheduled to be held on May 22, 1998.

Indicate by check mark if disclosure of delinquent filers to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]

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Western Gas Resources, Inc.
Form 10-K
Table of Contents

Part Item(s) Page
- ------ ------- ----

I. 1 and 2. Business and Properties.............................................. 3
General.......................................................... 3
Principal Facilities............................................. 4
Gas Gathering, Processing, Storage and Transmission.............. 5
Significant Acquisitions, Projects and Dispositions.............. 7
Marketing........................................................ 10
Producing Properties............................................. 12
Competition...................................................... 13
Regulation....................................................... 13
Employees........................................................ 13
3. Legal Proceedings.................................................... 14
4. Submission of Matters to a Vote of Security Holders.................. 14
II. 5. Market for Registrant's Common Equity and Related Stockholder Matters 14
6. Selected Financial Data.............................................. 15
7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.............................................. 16
8. Financial Statements and Supplementary Data.......................... 26
9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure............................................... 55
III. 10. Directors and Executive Officers of the Registrant................... 55
11. Executive Compensation............................................... 55
12. Security Ownership of Certain Beneficial Owners and Management....... 55
13. Certain Relationships and Related Transactions....................... 55
IV. 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K..... 55

2

PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

GENERAL
Western Gas Resources, Inc. (the "Company") is an independent gas gatherer and
processor and energy marketer providing a full range of services to its
customers from the wellhead to the delivery point. The Company designs,
constructs, owns and operates natural gas gathering, processing, treating and
storage facilities in major gas-producing basins in the Rocky Mountain, Mid-
Continent, Gulf Coast and Southwestern regions of the United States. The
Company connects producers' wells to its gathering systems for delivery to its
processing or treating plants, processes the natural gas to extract natural gas
liquids ("NGLs") and treats the natural gas in order to meet pipeline
specifications. The Company markets gas and NGLs nationwide and in Canada,
providing risk management, storage, transportation, scheduling, peaking and
other services to a variety of customers. The Company explores and develops
certain producing properties, primarily in Wyoming, Louisiana and Texas, in
support of its existing facilities and to expand into new producing areas.

Historically, the Company has derived over 95% of its revenues from the sale of
gas and NGLs. Set forth below are the Company's revenues by type of operation
(000s):

Year Ended December 31,
----------------------------------------------------------------
1997 % 1996 % 1995 %
---------------- ------ ---------- ------ ---------- ------

Sale of gas...................................... $1,657,479 69.5 $1,440,882 68.9 $ 876,399 69.7
Sale of NGLs..................................... 611,969 25.7 561,581 26.9 331,760 26.4
Sale of electric power........................... 59,477 2.5 30,667 1.5 - -
Processing, transportation and storage revenues.. 40,906 1.7 44,943 2.1 41,358 3.3
Other, net....................................... 15,429 .6 12,936 .6 7,467 .6
---------- ----- ---------- ----- ---------- -----
$2,385,260 100.0 $2,091,009 100.0 $1,256,984 100.0
========== ===== ========== ===== ========== =====

The Company has expanded through acquisitions, internal project development and
increased marketing activity. This expansion has strengthened the Company's
position in major producing basins and increased its access to multiple natural
gas markets. The table below illustrates the Company's growth over the last
five years:

Average for the Year Ended
Average -------------------------------------
Average NGL Gas Gas NGL
Gas Sales Sales Throughput Production Production
(MMcf/D) (MGal/D) (MMcf/D) (MMcf/D) (MGal/D)
---------- -------- ----------- ----------- -----------

December 31, 1992.. 442 2,400 669 331 1,874
December 31, 1997.. 1,975 4,585 1,229 1,053 2,264
% increase......... 347 91 84 218 21

The Company's four-part business plan is designed to increase profitability
through: (i) investing in projects that complement and extend its core gas
gathering, processing and marketing business; (ii) creating ventures with
producers who will dedicate additional acreage to the Company; (iii) expanding
its energy sales volumes and margins by maximizing its asset base, firm
transportation and storage contracts and other contractual arrangements; and
(iv) optimizing the profitability of existing operations. See further discussion
in "Management's Discussion and Analysis of Financial Condition and Results of
Operations - Business Strategy."

This section, as well as other sections in this Form 10-K, contain "forward-
looking statements" within the meaning of the Private Securities Litigation
Reform Act of 1995, which can be identified by the use of forward-looking
terminology, such as "may," "intend," "will," "expect," "anticipate,"
"estimate," or "continue" or the negative thereof or other variations thereon or
comparable terminology. This Form 10-K contains forward-looking statements
regarding the expansion of the Company's gathering operations, its project
development schedules, marketing plans, throughput capacity and anticipated
volumes that involve a number of risks and uncertainties, including the
composition of gas to be treated and the drilling schedules and success of the
producers dedicated to the Company's facilities. In addition to the important
factors referred to herein, numerous other factors affecting the gas processing
industry generally and in the markets for gas and NGLs in which the Company
operates, could cause actual results to differ materially. See further
discussion in "Financial Statements and Supplementary Data - Notes to
Consolidated Financial Statements - Note 2 - Summary of Significant Accounting
Policies - Use of Estimates and Significant Risks."

The Company's principal offices are located at 12200 North Pecos Street, Denver,
Colorado 80234-3439, and its telephone number is (303) 452-5603. The Company
was incorporated in Delaware in 1989.

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PRINCIPAL FACILITIES

The following table provides information concerning the Company's principal
facilities. The Company also owns and operates several smaller treating and
processing facilities located in the same areas as its other facilities.

Average for the Year Ended
December 31, 1997
Gas Gas --------------------------------------------
Gathering Throughput Gas Gas NGL
Year Placed Systems Capacity Throughput Production Production
Plant Facilities (1) In Service Miles(2) (MMcf/D)(3) (MMcf/D)(4) (MMcf/D)(5) (MGal/D)(5)
- ------------------------------- ----------- ------------- ------------- ------------- ------------- -----------

SOUTHERN REGION:
Texas
Bethel Treating (6).......... 1997 79 350 42 38 -
Edgewood (6)(7).............. 1964 89 65 26 8 63
Giddings Gathering........... 1979 656 80 60 51 84
Gomez Treating............... 1971 307 280 156 151 -
Midkiff/Benedum.............. 1955 2,127 165 152 99 948
Mitchell Puckett Gathering... 1972 86 85 80 79 -
MiVida Treating (6).......... 1972 287 150 66 63 -
Perkins (8).................. 1975 2,573 40 21 12 134
Rosita Treating.............. 1973 - 60 39 39 -
Louisiana
Black Lake................... 1966 56 75 22 14 61
Toca (7)(9).................. 1958 - 160 101 97 69
NORTHERN REGION:
Wyoming
Coal Bed Methane
Gathering (10).............. 1990 139 55 37 33 -
Granger (7)(11)(12)(13)...... 1987 366 235 146 128 288
Hilight Complex (7).......... 1969 622 80 38 32 89
Kitty/Amos Draw (7).......... 1969 307 17 11 7 46
Lincoln Road (13)............ 1988 149 50 32 31 29
Newcastle (7)................ 1981 145 5 2 1 16
Red Desert (7)............... 1979 111 42 22 21 37
Reno Junction (11)........... 1991 - - - - 56
Oklahoma
Arkoma....................... 1985 63 8 5 5 -
Chaney Dell (14)............. 1966 2,042 180 78 62 242
Westana (14)................. 1986 726 45 59 51 97
New Mexico
San Juan River (6)........... 1955 130 60 31 28 1
Utah
Four Corners Gathering....... 1988 104 15 3 3 4
------ ----- ----- ----- -----
Total....................... 11,164 2,302 1,229 1,053 2,264
====== ===== ===== ===== =====

Average for the
Year Ended
December 31, 1997
Interconnect -----------------
and Gas Storage Pipeline Gas
Storage and Year Placed Transmission Capacity Capacity Throughput
Transmission Facilities (1) In Service Miles(2) (Bcf)(2) (MMcf/D)(2) (MMcf/D)(4)
- ------------------------------- ----------- ------------ ---------- ---------- ---------------

Katy Facility (15)............. 1994 17 20 - 250
MIGC (16)...................... 1970 245 - 90 58
MGTC (17)...................... 1963 252 - 18 9
------ ----- ----- -----
Total........................ 514 20 108 317
====== ===== ===== =====

- ------------------
Footnotes on following page.

4

(1) The Company's interest in all facilities is 100% except for
Midkiff/Benedum (73%); Black Lake (69%); Lincoln Road (72%); Westana
Gathering Company ("Westana") (50%); Newcastle (50%) and Coal Bed Methane
Gathering (50%). All facilities are operated by the Company and all data
include interests of the Company, other joint interest owners and
producers of gas volumes dedicated to the facility.
(2) Gas gathering systems miles, interconnect and transmission miles, gas
storage capacity and pipeline capacity are as of December 31, 1997.
(3) Gas throughput capacity is as of December 31, 1997 and represents capacity
in accordance with design specifications unless other physical constraints
exist, including permitting or field compression limits.
(4) Aggregate wellhead natural gas volumes collected by a gathering system,
aggregate residue volumes delivered over the header at the Katy Hub and
Gas Storage Facility ("Katy Facility") or residue volumes transported by a
pipeline.
(5) Volumes of gas and NGLs are allocated to a facility when a well is
connected to that facility; volumes exclude NGLs fractionated for third
parties.
(6) Sour gas facility (capable of processing or treating gas containing
hydrogen sulfide and/or carbon dioxide).
(7) Fractionation facility (capable of fractionating raw NGLs into end-use
products).
(8) In November 1997, the Company entered into an agreement to sell its
Perkins facility. The sales price is $22.0 million, subject to certain
adjustments, and is expected to result in a pre-tax gain of approximately
$11.0 million. The sale is pending Federal Trade Commission approval. The
Company expects to obtain such approval and for the sale to close during
the first quarter of 1998.
(9) Straddle plant (a plant located near a transmission pipeline that
processes gas dedicated to or gathered by a pipeline company or another
third party).
(10) On October 30, 1997, the Company sold a 50% undivided interest in its
Powder River Basin coal bed methane gas operations. The sale involved
gathering assets, producing properties, production equipment and certain
undeveloped acreage in this area. See further discussion in "Significant
Acquisitions, Projects and Dispositions."
(11) NGL production includes conversion of third-party feedstock to iso-butane.
(12) In February 1998, the Company sold a 50% undivided interest in a portion
of the Granger gathering system for approximately $4.0 million. This
amount approximated the Company's cost in such facilities. See further
discussion in "Significant Acquisitions, Projects and Dispositions."
(13) The Company and its joint venture partner at the Lincoln Road facility
have agreed to process such gas at the Company's Granger facility as long
as there is available capacity at the Granger facility. As a result, a
periodic election is made as to whether or not gas will be processed at
the Lincoln Road facility. Accordingly, operations at the Lincoln Road
facility were temporarily suspended for the period between March 1996 and
April 1997. Beginning February 1998, processing at the Lincoln Road
facility was again temporarily suspended.
(14) Gas throughput and gas production in excess of plant throughput capacity
is unprocessed gas delivered to the Company's Chaney Dell facility for
processing or delivered into an unaffiliated pipeline. These processed
volumes are included in Westana's NGL production volumes.
(15) Hub and gas storage facility.
(16) MIGC is an interstate pipeline located in Wyoming and is regulated by the
Federal Energy Regulatory Commission ("FERC").
(17) MGTC is a public utility located in Wyoming and is regulated by the
Wyoming Public Service Commission.

Capital expenditures related to existing operations are expected to be
approximately $129.4 million during 1998, consisting of the following: capital
expenditures related to gathering, processing and pipeline assets are expected
to be approximately $84.8 million, of which approximately $74.8 million is
budgeted to be used for new connects, system expansions and asset consolidations
and approximately $10.0 million for maintaining existing facilities. The
Company expects capital expenditures on exploration and production activities,
the Katy Facility and miscellaneous items to be approximately $40.2 million,
$1.5 million and $2.9 million, respectively.

GAS GATHERING, PROCESSING, STORAGE AND TRANSMISSION

Gas Gathering and Processing

The Company contracts with producers to gather raw natural gas ("natural gas")
from individual wells located near its plants. Once a contract has been
executed, the Company connects wells to gathering lines through which the
natural gas is delivered to a processing plant or treating facility. At a
processing plant, the natural gas is compressed, unfractionated NGLs are
extracted and the remaining dry gas is treated to meet pipeline quality
specifications ("residue gas" or "gas"). Seven of the Company's processing
plants can further separate, or fractionate, the mixed NGL stream into ethane,
propane, normal butane

5

and natural gasoline to obtain a higher value for the NGLs and four of the
Company's plants are able to process and treat natural gas containing hydrogen
sulfide or other impurities which require removal prior to transportation. In
addition, the Company has two facilities which convert normal butane into iso-
butane. At a treating facility, dry gas, which does not contain liquids that can
economically be extracted, is treated to meet pipeline quality specifications by
removing hydrogen sulfide or carbon dioxide.

The Company continually acquires additional dedicated natural gas supplies in an
effort to maintain or increase throughput levels to offset natural production
declines in dedicated volumes. Such natural gas supplies are obtained by
purchasing existing systems from third parties, by connecting additional wells,
through internally developed projects or through joint ventures with entities
which control acreage. Historically, while certain individual plants have
experienced declines in dedicated reserves, the Company has been successful in
connecting additional reserves to more than offset the natural declines and
reserves dedicated to existing facilities. Drilling activity in certain basins
in which the Company operates has continued to be significantly reduced from
levels that existed in prior years. However, higher gas prices experienced since
the beginning of 1996, improved technology (e.g., 3-D seismic and horizontal
drilling) and increased pipeline capacity from the Rocky Mountain region have
stimulated drilling in certain of the basins in which the Company operates,
primarily the Permian Basin, the Cotton Valley Pinnacle Reef trend, Powder River
Basin and Southwest Wyoming. The level of drilling will depend upon, among other
factors, the prices for gas and oil, the energy policy of the federal government
and the availability of foreign oil and gas, none of which are within the
Company's control. There is no assurance that the Company will continue to be
successful in replacing the dedicated reserves processed at its facilities. In
1997, including the reserves associated with the Company's joint ventures and
partnerships, the Company connected new reserves to its gathering systems to
replace approximately 220% of 1997 production. On a Company-wide basis,
dedicated reserves increased from approximately 2.8 Tcf as of December 31, 1996
to approximately 3.3 Tcf at December 31, 1997.

Substantially all gas flowing through the Company's facilities is supplied under
long-term contracts providing for the purchase, treating or processing of
natural gas for periods ranging from five to twenty years, using three basic
contract types. Approximately 70% of the Company's plant facilities' gross
margin (revenues at the plants less product purchases) for the year ended
December 31, 1997 resulted from percentage-of-proceeds agreements in which the
Company is typically responsible for arranging for the transportation and
marketing of the gas and NGLs. The price paid to producers is a specified
percentage of the net proceeds received from the sale of the gas and the NGLs.
This type of contract permits the Company and the producers to share
proportionally in price changes.

Approximately 15% of the Company's plant facilities' gross margin (revenues at
the plants less product purchases) for the year ended December 31, 1997 resulted
from contracts that are primarily fee-based whereby the Company receives a set
fee for each Mcf of gas gathered. This type of contract provides the Company
with a steady revenue stream that is not dependent on commodity prices, except
to the extent that low prices may cause a producer to curtail production. The
percentage of fee-based contracts is expected to increase as the volumes at the
Bethel Treating facility increase. See further discussion in "Significant
Acquisitions, Projects and Dispositions."

Approximately 15% of the Company's plant facilities' gross margin (revenues at
the plants less product purchases) for the year ended December 31, 1997 resulted
from contracts that combine gathering and compression fees with "keepwhole"
arrangements or wellhead purchases. Typically, producers are charged a
gathering and compression fee based upon volume. In addition, the Company
retains a predetermined percentage of the NGLs recovered by the processing
facility and keeps the producers whole by returning to the producers at the
tailgate of the plant an amount of residue gas equal on a Btu basis to the
natural gas received at the plant inlet. The "keepwhole" component of the
contracts permits the Company to benefit when the value of the NGLs is greater
as a liquid than as a portion of the residue gas stream. However, when the
value of the NGLs is lower as a liquid than as a portion of the residue gas
stream, the Company will be unfavorably affected.

Storage and Transmission

In order to enhance the Company's gas marketing activities, it constructed the
Katy Facility. The Company commenced operations of the Katy Facility in
February 1994. The Katy Facility, which is located approximately 20 miles from
Houston, Texas, utilizes a partially depleted natural gas reservoir with 20 Bcf
of working gas capacity and a pipeline header system, currently connected to 11
pipelines, which has the capability to deliver up to 400 MMcf per day of gas
from the reservoir. See "Marketing - Gas."

6

The Company owns and operates MIGC, an interstate pipeline located in the Powder
River Basin in Wyoming and MGTC, an intrastate pipeline located in Northeast
Wyoming. As of December 31, 1997, MIGC is connected to the Colorado Interstate
Gas Pipeline, the Williston Basin Interstate Pipeline and the Pony Express
Pipeline. During November 1997, MIGC received approval from the FERC to
increase its pipeline capacity from 45 MMcf per day to 90 MMcf per day. The
compressors associated with this expansion began operating in December 1997. As
part of the Company's continuing plan to expand its Powder River Basin coal bed
methane operations, MIGC is currently seeking another approval from the FERC to
increase its pipeline capacity from 90 MMcf per day to 130 MMcf per day. The
Company anticipates receiving such approval during the third quarter of 1998.
See further discussion in "Significant Acquisitions, Projects and Dispositions."

SIGNIFICANT ACQUISITIONS, PROJECTS AND DISPOSITIONS

The Company's significant acquisitions and projects since January 1, 1995 are:

Coal Bed Methane

The Company is expanding its Powder River Basin coal bed methane natural gas
gathering system and developing its own coal seam gas reserves in Wyoming. The
Company has acquired drilling rights in the vicinity of known coal bed methane
production. The Company and other operators in the area have established
production from wells drilled to depths of 200 to 700 feet. The typical
gathering and completion costs associated with such drilling activities have
approximated $60,000 per well. As deeper wells are drilled, the average cost
per well is expected to increase. The Company will utilize its existing dry gas
gathering system and interstate pipeline to transport this pipeline quality gas
to market. The Company's capital budget provides for expenditures of
approximately $42.0 million during 1998. This capital budget includes
approximately $18.8 million for drilling costs, production equipment and
purchase of operating wells and undeveloped acreage. The remainder is to be
used primarily for compression equipment. Depending upon future drilling
success, additional capital expenditures will be required to continue expansion
in this basin. However, because of drilling and other uncertainties beyond the
Company's control, there can be no assurance that this level of capital
expenditure will be incurred or that future capital expenditures will be made.
During the years ended December 31, 1997 and 1996, the Company has expended
approximately $32.2 million and $6.9 million, respectively, on this project.

On October 30, 1997, the Company sold a 50% undivided interest in its Powder
River Basin coal bed methane gas operations to Barrett Resources Corporation
("Barrett"). This sale provides the Company with a substantial acreage
dedication within an area of mutual interest ("AMI"), additional man-power
resources to accelerate development in this area and more technical expertise in
exploration and production. The sale involved gathering assets, producing
properties, production equipment and certain undeveloped acreage in this area.
The final adjusted purchase price was $17.9 million, resulting in a pre-tax gain
of $4.7 million, which was recognized in the fourth quarter of 1997.

An AMI has been created under the agreement with Barrett which encompasses
approximately 2.1 million acres in the Powder River coal bed methane play. Both
parties will develop certain specified areas within the AMI, with Barrett
becoming the operator of the producing wells at the earlier of July 1, 1999 or
when production in the AMI reaches 60 MMcf per day. Production from the Powder
River coal bed methane play has been expanding over the last two years, and the
Company estimates that approximately 50 MMcf per day of gas volumes are
currently being produced from several operators in the area, including the
Company's interest. Most of the coal bed methane gas is being transported by
MIGC to gas markets in the Rocky Mountain and Midwest regions of the United
States. The Company has committed to purchase all gas produced from the jointly-
owned properties within the AMI under a long-term gas purchase agreement. The
Company entered into a firm transportation agreement under which MIGC will
install additional compression and transmission facilities as needed to handle
the anticipated increase in gas volumes.

In January 1998, the Company acquired an interest in approximately 25,000 acres,
which includes approximately 50 coal bed methane wells, located in Campbell
County, Wyoming. The Company will initially serve as operator of the properties.
Barrett has elected to participate in this project and will become the principal
operator. The Company's share of the purchase price was $6.4 million and is
subject to certain adjustments.

Southwest Wyoming

The Company began to expand its gas gathering and exploration and production
activities in Southwest Wyoming, including the Jonah field, during 1997. The
expansion in this area is primarily intended to develop acreage to replace
declines in reserves and generate additional volumes for gathering and
processing at its Granger and Lincoln Road facilities. The Company's capital

7

budget provides for expenditures of approximately $18.0 million during 1998.
This capital budget includes approximately $9.9 million for drilling costs and
production equipment and approximately $8.1 million related to gathering,
transportation and expansion of the Granger facility. Depending upon future
drilling success, additional capital expenditures will be required to continue
expansion in this basin. However, because of drilling and other uncertainties
beyond the Company's control, there can be no assurance that this level of
capital expenditure will be incurred or that future capital expenditures will be
made. During the year ended December 31, 1997, the Company has expended
approximately $6.2 million on this project.

In November 1997, the Company entered into an agreement with Ultra Resources,
Inc. ("Ultra") to participate in the exploration, development, gathering and
processing in the Hoback Basin in Southwestern Wyoming. Under the agreement, a
1.8 million acre AMI was established, in which Ultra currently controls
approximately 350,000 acres. The Company has the option to participate in
exploration and production activities for approximately a 15% interest. The
Company and Ultra have also entered into agreements for the natural gas, which
is developed on 16 prospects within the AMI, to be gathered and processed
through the Company's Granger facility. Eight of the 16 prospects were drilled
in 1997 and are in various stages of completion. The Company can expand the
area dedicated for gathering and acreage by funding Ultra's share of specified
development wells which will be paid back through future production.

Additionally, the Company entered into two separate agreements with RIS
Resources (USA) Inc. ("RIS"), an affiliate of Ultra, to sell RIS undivided
interests in certain assets. Under the first agreement, in February 1998, the
Company sold RIS a 50% undivided interest in a portion of the Granger gathering
system servicing the Ultra AMI (the "Bird Canyon Line") for approximately $4.0
million. This amount approximated the Company's cost in such facilities. RIS
and the Company expect to install jointly additional gathering assets in this
area as needed.

Under the second agreement with RIS, the Company has granted RIS the option to
purchase up to 50% of the Granger processing facility and its remaining
gathering system and up to a 50% interest in the Company's 72% ownership
interest in the Lincoln Road facility (collectively the "Granger Complex").
This option is exercisable in two 25% increments. The first option is
exercisable at any time prior to July 1, 1998 and the second option, which is
contingent upon the exercise of the first increment, is exercisable at any time
prior to July 1, 1999. In conjunction with this agreement, in February 1998,
RIS paid a $1 million option payment of which $500,000 is non-refundable. In
addition, RIS is required to pay an additional $59 million at the closing of the
first option and $50 million at the closing of the second option. The purchase
price will be further increased by a pro-rata share of capital expenditures
incurred at the Granger Complex from November 1997 until closing. These options
are subject to various regulatory approvals and third-party purchase
preferential rights. Pursuant to the agreement with RIS, the Company will remain
the operator of the Bird Canyon Line and the Granger Complex.

Bethel Treating Facility (Cotton Valley Pinnacle Reef)

In September 1996, the Company began constructing the Bethel Treating facility
in East Texas to gather and treat gas containing hydrogen sulfide and carbon
dioxide ("Sour Gas") from the Cotton Valley Pinnacle Reef Trend. The Company
embarked upon the project based upon producer reserve estimates, well rates
encountered by exploration companies and the need for a treating facility in
this area. The producer reserve estimates were based upon advancements in 3-D
seismic technology which facilitated the identification of potential pinnacle
reefs. Long-term gathering and treating agreements have been signed with
several producers, including Sonat Exploration Company ("Sonat"), UMC Petroleum
Corporation, Broughton Associates Joint Venture and Union Pacific Resources
Company, relating to their interests in the Cotton Valley Pinnacle Reef trend.
These agreements, in addition to other agreements, cover specified areas of
dedication aggregating approximately 650,000 acres of previously undedicated
interests and other individual wellsites.

Although the producers' reported success rates remain high in the Cotton Valley
Pinnacle Reef Trend, a number of producers in the trend are currently re-
evaluating their 1998 drilling plans downward. Pursuant to its agreement with
Sonat, the Company will begin treating additional volumes in May 1999 which are
currently being treated by a competitor. At present, this production is
approximately 100 MMcf per day.

In the third quarter of 1997, the Company completed the initial portion of the
Bethel Treating facility, which is capable of treating approximately 350 MMcf
per day, assuming 500 parts per million of hydrogen sulfide in the gas stream.
The Company has designed the Bethel Treating facility to accommodate incremental
expansions, depending upon the success of continued development in the trend.
To accommodate wells which contain greater concentrations of hydrogen sulfide,
the Company began to construct a 60-ton sulfur recovery plant which is expected
to become operational in March 1998. The

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Bethel Treating facility, including the sulfur recovery plant, is expected to
cost approximately $97.0 million, of which approximately $90.5 million has been
expended since inception through December 31, 1997. While the Bethel Treating
facility did not contribute to profitability during the year ended December 31,
1997, the Company anticipates that revenues will be sufficient to cover both
operating costs and depreciation at its current level of operation. See further
discussion in "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Results of Operations."

Reserve estimates are subject to numerous uncertainties inherent in the
estimation of quantities of reserves and in the projection of future rates of
production and the timing of development expenditures. A portion of the
production that is anticipated to be gathered and treated at the Bethel Treating
facility is expected to be produced from prospects that have not yet been
drilled and completed, and there can be no assurance of successful completion of
wells in these prospects. In addition, the carbon dioxide and hydrogen sulfide
content of the gas that can be produced from these wells is unknown and affects
the ultimate capacity of the Bethel Treating facility. Future expansions of the
Bethel Treating facility will be dependent upon drilling progress and permitting
of additional pipelines. Due to uncertainties related to future costs, possible
delays in pipeline permitting and other conditions outside the Company's
control, there can also be no assurance that further expansions of the Bethel
Treating facility will be economical.

Midkiff/Benedum

During 1997, the Company expanded the capacity at its Midkiff/Benedum processing
plant to approximately 165 MMcf per day. The expansion was to accommodate
increased drilling activity by Pioneer Natural Resources Company and other
producers which supply natural gas to this facility. The Company's share of the
expansion cost was approximately $4.3 million.

Perkins

In November 1997, the Company entered into an agreement to sell its Perkins
facility. The sales price is $22.0 million, subject to certain adjustments, and
is expected to result in a pre-tax gain of approximately $11.0 million. The sale
is pending Federal Trade Commission approval. The Company expects to obtain such
approval and for the sale to close during the first quarter of 1998.

Northern Acquisition

In July 1995, the Company purchased eight West Texas gathering systems,
consisting of approximately 230 miles of gathering lines in the Permian Basin,
from Transwestern Gathering Company and Enron Permian Gathering, Inc. The
adjusted purchase price was $18.7 million.

Redman Smackover Joint Venture

Effective January 1, 1995, the Company entered into the Redman Smackover Joint
Venture ("Redman Smackover") agreement with various third parties. Redman
Smackover acquired working interests in three producing gas fields in East Texas
in the Smackover formation for an adjusted purchase price of $11.0 million. The
Company is the managing venturer with a 50% ownership interest.

Other

The Company continually monitors the economic performance of each of its
operating facilities to ensure that a desired cash flow objective is achieved.
If an operating facility is not generating desired cash flows or does not fit in
with the Company's strategic plans, the Company will explore various options,
such as consolidation with other Company-owned facilities, dismantlement, asset
swap or outright sale.

The Company and its joint venture partner at the Lincoln Road facility have
agreed to process all such gas at the Company's Granger facility as long as
there is available capacity at the Granger facility. As a result, a periodic
election is made as to whether or not gas will be processed at the Lincoln Road
facility. Accordingly, operations at the Lincoln Road facility were temporarily
suspended for the period between March 1996 and April 1997. As a result of a
producer stopping delivery in December 1997 of approximately 40 MMcf per day of
gas,
9

processing at the Lincoln Road facility was again temporarily suspended. In
1996, the Company sold its Temple and Baker facilities and the remaining non-
strategic assets associated with a 1994 acquisition. In January 1996, Koch
Hydrocarbon Company, which operated the Teddy Roosevelt and Williston Gas
Company assets under a lease agreement, exercised its option to purchase certain
gas gathering assets located in North Dakota from the Company and Williston Gas
Company.

MARKETING

Gas

The Company markets gas produced at its plants and purchased from third parties
to end-users, local distribution companies ("LDCs"), pipelines and other
marketing companies throughout the United States and in Canada. Historically,
the Company's gas marketing was an outgrowth of the Company's gas processing
activities and was directed towards selling gas processed at its plants to
ensure their efficient operation. As the Company expanded into new basins and
the natural gas industry became deregulated and offered more opportunity, the
Company began to increase its third-party gas marketing. Since 1992, the
Company's gas sales volumes have increased by 347% to 2.0 Bcf per day for the
year ended December 31, 1997, primarily as a result of the increase in third-
party sales. Third-party sales and gas storage, combined with the stable supply
of gas from Company facilities, enable the Company to respond quickly to
changing market conditions and to take advantage of seasonal price variations
and peak demand periods. The Company sells gas under agreements with varying
terms and conditions in order to match seasonal and other changes in demand.
Most of the Company's current sales contracts range from a few days to two
years.

During 1997, the Company increased sales to end-users and expanded its marketing
in areas beyond its traditional gas supply centers. In general, the Company does
not expect dramatically to increase its third-party sales volumes from levels
achieved during the year ended December 31, 1997. Also during 1997, the Company
closed its Boston and Chicago offices. No significant costs were incurred as a
result of these office closures. The Company's 1998 gas marketing plan
emphasizes growth through its asset base and storage and transportation
capacities which it controls. However, it does intend to continue to develop and
market products tailored to meet the needs of end-users located primarily in the
Rocky Mountain region.

During 1997, the Company created a wholly-owned subsidiary to operate a
marketing office in Calgary, Alberta. In addition, the Company, through this
Canadian subsidiary, contracted capacity for approximately 4.1 Bcf of storage in
Canada. The Company anticipates that the Calgary office will (i) provide the
Company with information regarding gas supplies being transported from Canada;
(ii) establish a presence in an evolving gas market; and (iii) allow it to
increase profitability through its storage capacity.

The Company customarily stores gas in underground storage facilities to ensure
an adequate supply for long-term sales contracts and for resale during periods
when prices are favorable. In order to expand its ability to provide market
services and seasonal price differentials, the Company constructed the Katy
Facility. The ability to withdraw gas from the Katy Facility on short notice
positions the Company to market gas to LDCs and other customers that need a
reliable yet variable supply of gas. The Katy Facility's header system allows
the Company to bypass certain transportation bottlenecks and enhances
flexibility in its marketing operations. In addition, as of December 31, 1997,
the Company had contracts in place for approximately 16.1 Bcf of storage
capacity, including storage through its Canadian subsidiary, for resale during
periods when prices are favorable. The fees associated with such contracts range
from $.05 per Mcf to $1.25 per Mcf and the associated periods range from one
month to one year. As of December 31, 1997, the Company also had contracts for
approximately 400 MMcf per day of firm transportation; 50% of such contracts
expire during 1998. The fees associated with such contracts do not exceed $.37
per Mcf per day and the associated periods range from one month to ten years.
Certain of these long-term storage and firm transportation contracts require an
annual renewal. In addition, certain contracts contain provisions which would
require the Company to pay the fees associated with such contracts whether or
not the service was used.

The Company held gas in storage and held imbalances of approximately 6.0 Bcf
at an average cost of $1.97 per Mcf at December 31, 1997 compared to 10.4 Bcf at
an average cost of $1.84 per Mcf at December 31, 1996, at various storage
facilities, including the Katy Facility. At December 31, 1997, the Company had
hedging contracts in place for anticipated sales of approximately 4.8 Bcf of
stored gas at a weighted average price of $2.28 per Mcf for the stored
inventory. See further discussion in "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Liquidity and Capital Resources
- -Risk Management Activities."

10

The Company has a three-year, winter-peaking gas purchase and sales agreement
with a major utility in East Texas, expiring in March 1999, which designates the
Katy Facility as the primary delivery point. Under the agreement, the utility
has the right to purchase, during each year of the contract, up to approximately
100 MMcf per day and 70 MMcf per day of gas in November and March, respectively,
and approximately 140 MMcf per day of gas in December, January and February, at
a monthly index price plus a fixed charge. The agreement calls for a minimum
charge to be paid to the Company for each contract term, whether or not delivery
is taken. This minimum charge is calculated based upon five Bcf of annual
storage during each fiscal year of the contract term.

In February 1995, the Company entered into a long-term firm storage and
transportation agreement with a St. Louis-based LDC that expires in March 2000.
Under the agreement, the Company has leased approximately three Bcf of storage
capacity of the Katy Facility to the LDC. The gas will principally serve local
distribution requirements of the LDC's customers in central Missouri.

During the year ended December 31, 1997, the Company sold gas to approximately
500 end-users, pipelines, LDCs and other customers. No single gas customer
accounted for more than 4% of consolidated revenues for the year ended December
31, 1997.

NGL Marketing

The Company markets NGLs (ethane, propane, iso-butane, normal butane, natural
gasoline and condensate) produced at its plants and purchased from third parties
in the Rocky Mountain, Mid-Continent, Gulf Coast and Southwestern regions of the
United States. A majority of the Company's production of NGLs moves to the Gulf
Coast area, which is the largest NGL market in the United States. Through the
development of end-use markets and distribution capabilities, the Company seeks
to ensure that products from its plants move on a reliable basis, avoiding
curtailment of production. For the year ended December 31, 1997, NGL sales
averaged 4,585 MGal per day, an increase from 2,400 MGal per day in 1992,
primarily due to the increase in third-party sales, acquisitions and facility
expansions during the five-year period. The volatility of NGL prices causes the
Company to move to short-term contracts for its NGL marketing activities, with
no prices set on a firm basis for more than a 30-day period. Although some
existing contracts do commit the Company for periods as long as three years,
prices are typically redetermined on a market-related basis.

Consumption of NGLs is primarily determined by various end-user markets
including the petrochemical industry, the petroleum refining industry and the
retail and industrial fuel markets. As an example, the petrochemical industry
uses ethane, propane, normal butane and natural gasoline as feedstocks in the
production of ethylene, which is used in the production of various plastics
products. Over the last several years, the petrochemical industry has increased
its use of NGLs as a major feedstock and is projected to continue to increase
such usage. Further, propane is used for home heating, transportation and for
certain agricultural applications. Demand for NGLs is primarily affected by
price, seasonality and the economy.

The Company increased sales to third parties by approximately 800 MGal per day
for the year ended December 31, 1997 compared to 1996. In general, the Company
does not anticipate that sales to third parties in 1998 will increase at the
rate experienced in 1997. The NGL marketing plan contemplates: (i) continued
growth in sales to end-users; (ii) maximizing profitability on volumes produced
at the Company's facilities; and (iii) efficient use of various third-party
storage facilities to increase profitability while limiting carrying risk.

The Company leases NGL storage space at major trading locations, primarily near
Houston and in central Kansas, in order to store products so that they can be
sold at higher prices on a seasonal basis and to facilitate the distribution of
products. In addition, as of December 31, 1997, the Company has contracts in
place for approximately 27,300 MGal of storage capacity for resale during
periods when prices are favorable. The base fees associated with such
contracts currently do not exceed $.02 per gallon and the associated periods
range from three months to five years. Certain of the long-term contracts
require an annual renewal and contain provisions which would require the Company
to pay the fees associated with such contracts whether or not the service was
used.

The Company held NGLs in storage of 14,400 MGal, consisting primarily of propane
and normal butane, at an average cost of $.37 per gallon and 16,100 MGal at an
average cost of $.42 per gallon at December 31, 1997 and 1996, respectively, at
various third-party storage facilities. At December 31, 1997, the Company had
hedging contracts in place for anticipated sales, consisting primarily of
propane, at a weighted average price of $.36 per gallon for approximately 3,200
MGal of the stored NGLs in inventory. The Company generally intends that stored
NGLs turn over on an annual basis.

11

NGL sales were made to approximately 175 different customers and no single
customer accounted for more than 2% of the Company's consolidated revenues for
the year ended December 31, 1997. Revenues are also derived from contractual
marketing fees charged to some producers for NGL marketing services. For the
year ended December 31, 1997, such fees were less than 1% of the Company's
consolidated revenues.

Power Marketing

In July 1996, the FERC issued its final order requiring investor-owned electric
utilities to provide open access for wholesale transmission. This action allows
companies to participate in a market previously controlled by electric
utilities. During 1996 and 1997, the Company traded electric power in the
wholesale market and entered into transactions that arbitraged the value of gas
and electric power. Due to a lack of profitability, the Company elected to
discontinue trading electric power and began to evaluate its role in this
emerging business, during the second half of 1997.

PRODUCING PROPERTIES

Revenues derived from the Company's producing properties comprised approximately
1.3%, 1.6% and 2.6% of consolidated revenues, respectively, for the years ended
December 31, 1997, 1996 and 1995. During 1997, the Company began to invest more
capital in oil and gas producing activities primarily to replace declining
reserves which are processed at the Company's facilities and encourage expansion
into basins where the Company's facilities are located. The Company believes
that in order to secure additional gas supply for its facilities, it must be
willing to increase its participation in exploration and production activities.
However, the Company, where possible, has entered into agreements with third
parties to reduce a portion of the risk associated with exploration and
production activities. The net annual production volumes are summarized as
follows:

December 31,
-------------------------------------------------
1997 1996 1995
--------------- ---------------- --------------
Gas Oil Gas Oil Gas Oil
State (MMcf) (MBbl) (MMcf) (MBbl) (MMcf) (MBbl)
- ---------------------------- ------- ------ ------- ------ ------- ------

Colorado.................... 243 6 73 6 73 6
Louisiana................... 4,760 108 7,255 117 11,429 131
Texas....................... 6,092 21 7,193 32 6,588 61
Wyoming:
Coal Bed Methane.......... 1,751 - 12 - - -
All Other................. 1,752 19 233 3 263 2
------ --- ------ --- ------ ----

Total....................... 14,598 154 14,766 158 18,353 200
====== === ====== === ====== ====

Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of"
("SFAS No. 121"), which requires that an impairment loss be recognized when the
carrying amount of an asset exceeds the fair market value or the expected future
undiscounted net cash flows. SFAS No.121 also requires long-lived assets be
reviewed whenever events or changes in circumstances indicate that the carrying
value of such assets may not be recoverable. As a result of a review of the
reserves, the Company determined that circumstances had changed, primarily
related to its Black Lake facility and Sand Wash Basin assets, and an impairment
evaluation was necessary. In order to determine whether an impairment existed,
the Company compared its net book value of the assets to the estimated fair
market value or the undiscounted expected future cash flows, determined by
applying future prices estimated by management over the lives of the associated
reserves. Where impairment existed, assets were written-down to the net present
value of expected cash flows discounted using an interest rate commensurate with
the risk associated with the underlying asset. As a result of this analysis,
the Company recognized a pre-tax, non-cash loss on the impairment of property
and equipment of $34.6 million.

Reserve estimates are subject to numerous uncertainties inherent in the
estimation of quantities of proved reserves and in the projection of future
rates of production and the timing of development expenditures. The accuracy of
such estimates is a function of the quality of available data and of engineering
and geological interpretation and judgment. Estimates of economically
recoverable reserves and of future net cash flows expected therefrom prepared by
different engineers or by the same engineers at different times may vary
substantially. Results of subsequent drilling, testing and production may cause

12

either upward or downward revisions of previous estimates. Further, the volumes
considered to be commercially recoverable fluctuate with changes in prices and
operating costs. Any significant revision of reserve estimates could materially
adversely affect the Company's financial condition and results of operations.

COMPETITION

The Company competes with other companies in the gathering, processing, treating
and marketing businesses both for supplies of natural gas and for customers for
its gas and NGLs. Competition for natural gas supplies is primarily based on
efficiency, reliability, availability of transportation and ability to obtain
a satisfactory price for the producers' natural gas. Competition for customers
is primarily based upon reliability and price of deliverable gas and NGLs. For
customers that have the capability of using alternative fuels, such as oil and
coal, the Company also competes based primarily on price against companies
capable of providing such alternative fuels. The Company's competitors for
obtaining additional natural gas supplies, for gathering and processing natural
gas and for marketing gas and NGLs include national and local gas gatherers,
brokers, marketers and distributors of various size, financial resources and
experience.

REGULATION

The purchase and sale of natural gas and the fees received for gathering and
processing by the Company have generally not been subject to regulation and,
therefore, except as constrained by competitive factors, the Company has
considerable pricing flexibility. Many aspects of the gathering, processing,
marketing and transportation of natural gas and NGLs by the Company, however,
are subject to federal, state and local laws and regulations which can have a
significant impact upon the Company's overall operations.

As a processor and marketer of natural gas, the Company depends on the
transportation and storage services offered by various interstate and intrastate
pipeline companies for the delivery and sale of its own gas supplies as well as
those it processes and/or markets for others. Both the performance of
transportation and storage services by interstate pipelines, and the rates
charged for such services, are subject to the jurisdiction of the FERC under the
Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The
availability of interstate transportation and storage service necessary to
enable the Company to make deliveries and/or sales of gas can at times be pre-
empted by other system users in accordance with FERC-approved methods for
allocating the system capacity of "open access" pipelines. Moreover, the rates
charged by pipelines for such services are often subject to negotiation between
shippers and the pipelines within certain FERC-established parameters and will
periodically vary depending upon individual system usage and other factors. An
inability to obtain transportation and/or storage services at competitive rates
can hinder the Company's processing and marketing operations and/or affect its
sales margins.

In 1997, the State of Texas adopted a statute that will require the Company to
obtain a pre-construction permit for certain gas gathering lines containing more
than 100 parts per million of hydrogen sulfide and grants affected persons, in
certain circumstances, the right to request a hearing relating to the issuance
of such a permit. This may increase the time and cost associated with
constructing hydrogen sulfide gathering lines. The Company operates three
facilities in Texas which treat hydrogen sulfide; the Edgewood facility, the
MiVida Treating facility and the Bethel Treating facility, and owns certain
producing properties in Texas that produce hydrogen sulfide.

Generally, gathering and processing prices are not regulated by the FERC or any
state agency. However, in May 1995, the Oklahoma Corporation Commission (the
"OCC") was granted limited authority in certain circumstances, after the filing
of a complaint by a producer, to compel a gas gatherer to provide open access
gathering and to set aside unduly discriminatory gathering fees. The Oklahoma
state legislature is considering legislation that would greatly expand the
authority of the OCC to compel a gas gatherer to provide open access gas
gathering and to establish rates, terms and conditions of services provided by a
gas gatherer. In addition, the state legislatures and regulators in certain
other states in which the Company gathers gas are also contemplating additional
regulation of gas gathering. The Company does not believe that any of the
proposed legislation of which it is aware is likely to have a material adverse
effect on the Company's financial position or results of operation. However,
the Company cannot predict what additional legislation or regulations the states
may adopt regarding gas gathering.

EMPLOYEES

At December 31, 1997, the Company employed approximately 930 full-time
employees, none of whom was a union member. The Company considers relations with
employees to be excellent.

13

ITEM 3. LEGAL PROCEEDINGS

Reference is made to Note 9 of the Company's Consolidated Financial Statements
in Item 8 of this Form 10-K.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

There were no matters submitted to a vote of security holders during the quarter
ended December 31, 1997.

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS

As of February 27, 1998, there were 32,146,437 shares of Common Stock
outstanding held by 325 holders of record. The Common Stock is traded on the
New York Stock Exchange under the symbol "WGR." The following table sets forth
quarterly high and low sales prices as reported by the NYSE Composite Tape for
the quarterly periods indicated.

HIGH LOW
---------------- --------

1997
Fourth Quarter.................... $ 25 9/16 $ 20
Third Quarter..................... 22 1/2 16 3/4
Second Quarter.................... 20 1/2 14 7/8
First Quarter..................... 21 3/8 17 3/4

1996
Fourth Quarter.................... 19 7/8 13 7/8
Third Quarter..................... 16 3/8 13 1/8
Second Quarter.................... 16 3/4 13 1/2
First Quarter..................... $ 16 5/8 $ 11 1/8

The Company paid annual dividends on the Common Stock aggregating $.20 per share
during the years ended December 31, 1997 and 1996. The Company has declared a
dividend of $.05 per share of Common Stock for the quarter ending March 31, 1998
to holders of record as of such date. Declarations of dividends on the Common
Stock are within the discretion of the Board of Directors. In addition, the
Company's ability to pay dividends is restricted by certain covenants in its
financing facilities, the most restrictive of which prohibits declaring or
paying dividends after December 31, 1995 that exceed, in the aggregate, the sum
of $10 million plus 50% of the Company's cumulative consolidated net income
earned after December 31, 1995 plus 50% of the net proceeds received by the
Company after December 31, 1995 from the sale of any equity securities. The
dividends declared in the fourth quarter of 1995, payable in 1996, were excluded
from this calculation. At December 31, 1997, availability under this covenant
amounted to $118.5 million.

14

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected consolidated financial and operating
data for the Company. Certain prior year amounts have been reclassified to
conform to the presentation used in 1997. The data for the three years ended
December 31, 1997 should be read in conjunction with the Company's Consolidated
Financial Statements included elsewhere in this Form 10-K. The selected
consolidated financial data for the two years ended December 31, 1994 is derived
from the Company's historical Consolidated Financial Statements. See also Item
7 - "Management's Discussion and Analysis of Financial Condition and Results of
Operations."

Year Ended December 31,
--------------------------------------------------------------
1997 1996 1995 1994 1993
----------- ---------- ---------- ---------- ----------
(000s, except per share amounts and operating data)

STATEMENT OF OPERATIONS:
Revenues............................................... $2,385,260 $2,091,009 $1,256,984 $ 1,063,489 $ 932,338
Gross profit (a)....................................... 93,755 105,479 75,211 72,556 92,012
Income (loss) before income taxes...................... 2,220(b) 41,631 (8,266)(c) 11,524 55,631
Provision (benefit) for income taxes................... 733 13,690 (2,158) 4,160 17,529
Net income (loss)...................................... 1,487(b) 27,941 (6,108)(c) 7,364 38,102
Earnings (loss) per share of
common stock.......................................... (.28) .66 (.84) (.19) 1.25
Earnings (loss) per share of
common stock - assuming dilution...................... (.28) .66 (.84) (.19) 1.25

CASH FLOW DATA:
Net cash provided by operating
activities............................................ 114,755 168,266 86,373 31,866 107,116
Capital expenditures................................... 198,901 74,555 78,521 100,540 492,328

BALANCE SHEET DATA
(at year end):
Total assets........................................... 1,348,276 1,361,631 1,193,997 1,167,362 1,114,748
Long-term debt......................................... 441,357 379,500 529,500 493,000 547,000
Stockholders' equity................................... 468,112 480,467 371,909 436,683 314,387
Dividends declared per share of
common stock.......................................... $ .20 $ .20 $ .20 $ .20 $ .20

OPERATING DATA:
Average gas sales (MMcf/D)............................. 1,975 1,794 1,572 1,097 755
Average NGL sales (MGal/D)............................. 4,585 3,744 2,890 2,970 2,941
Average gas volumes
gathered (MMcf/D)..................................... 1,229 1,171 1,020 934 804
Facility capacity (MMcf/D)............................. 2,302 1,940 1,907 1,560 1,586
Average gas prices ($/Mcf)............................. $ 2.30 $ 2.19 $ 1.53 $ 1.77 $ 2.02
Average NGL prices ($/Gal)............................. $ .36 $ .41 $ .31 $ .28 $ .31

- ---------------

(a) Excludes selling and administrative, interest, restructuring and income tax
expenses and loss on the impairment of property and equipment. See further
discussion in notes (b) and (c).
(b) Statement of Financial Accounting Standards No.121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of"
("SFAS No. 121"), requires that an impairment loss be recognized when the
carrying amount of an asset exceeds the fair market value of or the expected
future undiscounted net cash flows. In accordance with SFAS No. 121, the
Company recognized a pre-tax, non-cash loss on the impairment of property
and equipment of $34.6 million, pre-tax, and $22.0 million, after-tax.
(c) In accordance with SFAS No. 121, the Company recognized a pre-tax, non-cash
loss on the impairment of property and equipment of $17.6 million, pre-tax,
and $12.4 million, after-tax. Also, the Company implemented a cost reduction
program to reduce operating and selling and administrative expenses. As a
result of this program, a $2.1 million, pre-tax, and $1.3 million, after-
tax, restructuring charge was incurred, primarily related to employee
severance costs.

15

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

The following discussion and analysis relates to factors that have affected the
consolidated financial condition and results of operations of the Company for
the three years ended December 31, 1997. Certain prior year amounts have been
reclassified to conform to the presentation used in 1997. Reference should also
be made to the Company's Consolidated Financial Statements and related Notes
thereto and the Selected Financial Data included elsewhere in this Form 10-K.

RESULTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
(000S, EXCEPT PER SHARE AMOUNTS AND OPERATING DATA)

Year Ended
December 31,
------------------------- Percent
1997 1996 Change
------------- ---------- -------

FINANCIAL RESULTS:
Revenues....................................................... $2,385,260 $2,091,009 14
Gross profit................................................... 93,775 105,479 (11)
Net income..................................................... 1,487 27,941 (95)
Earnings (loss) per share of common stock...................... (.28) .66 -
Earnings (loss) per share of common stock - assuming dilution.. (.28) .66 -
Net cash provided by operating activities...................... $ 114,755 $ 168,266 (32)

OPERATING DATA:
Average gas sales (MMcf/D)..................................... 1,975 1,794 10
Average NGL sales (MGal/D)..................................... 4,585 3,744 22
Average gas prices ($/Mcf)..................................... $ 2.30 $ 2.19 5
Average NGL prices ($/Gal)..................................... $ .36 $ .41 (12)

Net income decreased $26.5 million for the year ended December 31, 1997 compared
to 1996. The decrease in net income for the year was primarily due to a $22.0
million, after-tax, impairment loss recorded in connection with the evaluation
of certain property and equipment, primarily related to its Black Lake facility
and Sand Wash Basin assets, as required by SFAS No. 121. Net income increased
by a $3.0 million after-tax gain associated with the sale of a 50% interest in
the Company's coal bed methane operations.

Revenues from the sale of gas increased approximately $216.6 million for the
year ended December 31, 1997 compared to 1996. Average gas sales volumes
increased 181 MMcf per day to 1,975 MMcf per day for the year ended December 31,
1997 compared to 1996, primarily due to an increase in the sale of gas purchased
from third parties. Average gas prices realized by the Company increased $.11
per Mcf to $2.30 per Mcf for the year ended December 31, 1997 compared to 1996.
Included in the realized gas price was approximately $5.6 million of loss
recognized in the year ended December 31, 1997 related to futures positions on
equity volumes. The Company has entered into futures positions for a portion of
its equity gas for 1998. See further discussion in "Liquidity and Capital
Resources - Risk Management."

Revenues from the sale of NGLs increased approximately $50.4 million for the
year ended December 31, 1997 compared to 1996. Average NGL sales volumes
increased 841 MGal per day to 4,585 MGal per day for the year ended December 31,
1997 compared to 1996, largely due to an increase of approximately 800 MGal per
day in the sale of NGLs purchased from third parties. Average NGL prices
realized by the Company decreased $.05 per gallon to $.36 per gallon for the
year ended December 31, 1997 compared to 1996. Included in the realized NGL
price was approximately $5.2 million of gain recognized in the year ended
December 31, 1997 related to futures positions on equity volumes. The Company
has entered into futures positions for a portion of its equity production for
1998. See further discussion in "Liquidity and Capital Resources - Risk
Management."

Revenue associated with electric power marketing increased $28.8 million for the
year ended December 31, 1997 compared to 1996, primarily because the Company had
minimal transactions in this market during 1996. Due to a lack of profitability,
the Company elected to discontinue trading electric power and began to evaluate
its role in this emerging business,

16

during the second half of 1997. Accordingly, revenue in 1998 and future years
will decrease compared to 1997.

The increase in product purchases of $302.3 million to $2.1 billion for the
year ended December 31, 1997 compared to 1996, is primarily a combination of
higher gas prices and increased sales of NGLs purchased from third parties.
Contributing to the increase in product purchases for the year ended December
31, 1997 compared to 1996 were higher payments to producers related to the
Company's "keepwhole" contracts at its Granger facility. Under a "keepwhole"
contract, the Company's margin is reduced when the value of NGLs declines
relative to the value of gas. Also, contributing to the increases in product
purchases for the year ended December 31, 1997 compared to 1996, were lower of
cost or market write-downs of NGL and gas inventories of $1.1 million and
$129,000, respectively.

Plant operating expense increased approximately $5.0 million for the year ended
December 31, 1997 compared to 1996. The increase was primarily due to additional
compression costs associated with the MIGC pipeline. In addition, results of
operations for the year ended December 31, 1997 were adversely affected by
additional costs associated with the Bethel Treating facility. As a result of
start-up costs associated with opening the facility and depreciation, the Bethel
Treating facility did not contribute positively to earnings in 1997.

Depreciation, depletion and amortization decreased $4.0 million for the year
ended December 31, 1997 compared to 1996. The decrease was primarily due to
decreases in produced volumes related to the Company's Black Lake facility which
resulted in a decrease in the associated depletion.

Interest expense decreased $7.0 million for the year ended December 31, 1997
compared to 1996. The decrease in interest expense was primarily due to lower
average outstanding debt balances due to the use of the Company's net proceeds
from the November 1996 public offering of 6,325,000 shares of Common Stock to
reduce indebtedness under the Revolving Credit Facility. However, the Company's
borrowings under its long-term debt agreements, as of December 31, 1997, are
consistent with prior year balances, primarily due to costs associated with the
construction of the Bethel Treating facility. A portion of the decrease in
interest expense was also due to interest being capitalized related to the
construction of the Bethel Treating facility. The Bethel Treating facility is
expected to be substantially completed during the first quarter of 1998, at
which time interest will no longer be capitalized to this project.

Overall, profitability for the year ended December 31, 1997, was less than
anticipated due to several factors. Combined product purchases as a percentage
of gas, NGL and electric power sales increased from 91% to 92% for the year
ended December 31, 1997 compared to 1996. Over the past several years, the
Company has experienced narrowing margins related to the increasing
competitiveness of the natural gas marketing industry. During the year ended
December 31, 1997, the Company's marketing margins were reduced by approximately
50% compared to 1996. Included in the sale of gas and product purchases for the
last half of 1997, is the sale of approximately 11.5 Bcf of gas, previously
stored in the Katy Facility, at a margin of approximately $.20 per Mcf.

17

YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995
(000S, EXCEPT PER SHARE AMOUNTS AND OPERATING DATA)

Year Ended
December 31,
------------------------- Percent
1996 1995 Change
------------ ----------- ------

FINANCIAL RESULTS:
Revenues....................................................... $2,091,009 $1,256,984 66
Gross profit................................................... 105,479 75,211 40
Net income (loss).............................................. 27,941 (6,108) -
Earnings (loss) per share of common stock...................... .66 (.84) -
Earnings (loss) per share of common stock - assuming dilution.. .66 (.84) -
Net cash provided by operating activities...................... $ 168,266 $ 86,373 95

OPERATING DATA:
Average gas sales (MMcf/D)..................................... 1,794 1,572 14
Average NGL sales (MGal/D)..................................... 3,744 2,890 30
Average gas prices ($/Mcf)..................................... $ 2.19 $ 1.53 43
Average NGL prices ($/Gal)..................................... $ .41 $ .31 32

Net income increased $34.0 million and net cash provided by operating activities
increased $81.9 million for the year ended December 31, 1996 compared to 1995.
The increase in net income for the year was partially due to a $12.4 million,
after-tax, impairment loss recorded in 1995 in connection with the adoption of
SFAS No. 121 and a $1.3 million, after-tax, restructuring charge the Company
recorded in 1995 relating to its cost reduction program. In addition, net
income was positively affected by higher revenues attributable to increases in
prices and volumes, partially offset by higher product purchase costs associated
with the Company's third-party gas sales.

Revenues from the sale of gas increased approximately $564.5 million for the
year ended December 31, 1996 compared to 1995. Average gas sales volumes
increased 222 MMcf per day to 1,794 MMcf per day for the year ended December 31,
1996 compared to 1995, largely due to an increase of approximately 225 MMcf per
day in the sale of gas purchased from third parties, partially offset by
decreased sales at the Company's Black Lake facility. Average gas prices
realized by the Company increased $.66 per Mcf to $2.19 per Mcf for the year
ended December 31, 1996 compared to 1995. Included in the realized gas price
was approximately $7.2 million of loss recognized in the year ended December 31,
1996 related to futures positions on equity volumes.

Revenues from the sale of NGLs increased approximately $229.8 million for the
year ended December 31, 1996 compared to 1995. Average NGL sales volumes
increased 854 MGal per day to 3,744 MGal per day for the year ended December 31,
1996 compared to 1995, largely due to an increase of approximately 715 MGal per
day in the sale of NGLs purchased from third parties. Average NGL prices
realized by the Company increased $.10 per gallon to $.41 per gallon for the
year ended December 31, 1996 compared to 1995. Included in the realized NGL
price was approximately $11.6 million of loss recognized in the year ended
December 31, 1996 related to futures positions on equity volumes.

Revenue associated with electric power marketing was approximately $30.7
million; the Company entered this market at the end of 1995.

Other net revenue increased approximately $5.5 million for the year ended
December 31, 1996 compared to 1995. The increase was largely due to an increase
of approximately $2.9 million in partnership income, primarily attributable to
Redman Smackover, and a $1.9 million gain recognized on the sale of the Temple
facility.

The increase in product purchases corresponds to the increase in third-party
product sales. Combined product purchases as a percentage of gas, NGL and
electric power sales increased from 88% to 91% for the year ended December 31,
1996 compared to 1995. The increased product purchase percentage is a
continuing trend based upon the growth of third-party sales, which typically
have lower margins than sales of the Company's equity production. Over the past
several years, the Company has experienced narrowing margins related to the
increasing competitiveness of the natural gas marketing industry.

18

Selling and administrative expense increased $2.8 million for the year ended
December 31, 1996 compared to 1995, primarily as a result of growth in the
Company's marketing operations and higher benefit costs.

Depreciation, depletion and amortization decreased $2.2 million for the year
ended December 31, 1996 compared to the prior year. The decrease was
attributable to decreases in production related to the Company's oil and gas
properties, primarily at the Company's Black Lake facility. In addition, the
Company recorded a $17.6 million write-down of certain oil and gas assets and
plant facilities in the fourth quarter of 1995 in connection with its adoption
of SFAS No. 121. The lower asset values contributed to the reduction in
depreciation, depletion and amortization expense for the year ended December 31,
1996. These decreases were offset by increases related to various property
additions.

Interest expense decreased $2.7 million for the year ended December 31, 1996
compared to the prior year. The decrease was primarily due to the use of
improved cash flows from operations and the use of the Company's net proceeds
from the November 1996 public offering of 6,325,000 shares of Common Stock to
reduce indebtedness under the Revolving Credit Facility.

LIQUIDITY AND CAPITAL RESOURCES

The Company's sources of liquidity and capital resources historically have been
net cash provided by operating activities, funds available under its financing
facilities and proceeds from offerings of equity securities. In the past, these
sources have been sufficient to meet its needs and finance the growth of the
Company's business. The Company can give no assurance that the historical
sources of liquidity and capital resources will be available for future
development and acquisition projects, and it may be required to seek alternative
financing sources. Net cash provided by operating activities is primarily
affected by product prices and sales of inventory, the Company's success in
increasing the number and efficiency of its facilities and the volumes of
natural gas processed by such facilities, as well as the margin on third-party
product purchased for resale. The Company's continued growth will be dependent
upon success in the areas of marketing, additions to dedicated plant reserves,
acquisitions and new project development.

Historically, oil prices have been volatile and subject to rapid price
fluctuations. The oil and gas industry is currently experiencing significantly
declining oil prices. Such prices have declined approximately 25% during the
first quarter of 1998 to approximately $13.26 per barrell as of March 16, 1998.
In addition, the start-up volumes associated with the Bethel Treating facility
have been lower that anticipated. If the current price in of oil and associated
NGLs continues or declines and volumes associated with the Bethel Treating
facility do not increase, the Company is uncertain as to its ability to satisfy
its interest coverage covenants under certain of its debt agreements during the
last half of 1998. However, the Company believes it can obtain amendments or
waivers from the necessary lenders.

The Company believes that the amounts available to be borrowed under the
Revolving Credit Facility, together with cash provided by operating activities,
will provide it with sufficient funds to connect new reserves, maintain its
existing facilities and complete its current capital expenditure program.
Depending on the timing and the amount of the Company's future projects, it may
be required to seek additional sources of capital. The Company's ability to
secure such capital is restricted by its credit facilities, although it may
request additional borrowing capacity from its lenders, seek waivers from its
lenders to permit it to borrow funds from third parties, seek replacement credit
facilities from other lenders, use stock as a currency for an acquisition, sell
existing assets or a combination of such alternatives. While the Company
believes that it would be able to secure additional financing, if required, no
assurance can be given that it will be able to do so or as to the terms of any
such financing. Despite the declining oil prices experienced in the first
quarter of 1998, the Company also believes that cash provided by operating
activities will be sufficient to meet its debt service and preferred stock
dividend requirements in 1998.

19

The Company's sources and uses of funds for the year ended December 31, 1997 are
summarized as follows (000s):

SOURCES OF FUNDS:

Borrowings under revolving credit facility.. $1,894,950
Net cash provided by operating activities... 114,755
Other....................................... 20,273
----------

Total sources of funds................... $2,029,978
==========
USES OF FUNDS:
Payments related to long-term debt.......... $1,833,940
Capital expenditures........................ 198,901
Dividends paid.............................. 16,864
----------

Total uses of funds...................... $2,049,705
==========

Additional sources of liquidity available to the Company are volumes of gas and
NGLs in storage facilities. The Company stores gas and NGLs primarily to ensure
an adequate supply for long-term sales contracts and for resale during periods
when prices are favorable. The Company held gas in storage and held imbalances
for such purposes of approximately 6.0 Bcf at an average cost of $1.97 per
Mcf at December 31, 1997 compared to 10.4 Bcf at an average cost of $1.84 per
Mcf at December 31, 1996, at various storage facilities, including the Katy
Facility. At December 31, 1997, the Company had hedging contracts in place for
anticipated sales of approximately 4.8 Bcf of stored gas at a weighted average
price of $2.28 per Mcf for the stored inventory. The Company held NGLs in
storage of 14,400 MGal, consisting primarily of propane and normal butane, at an
average cost of $.37 per gallon and 16,100 MGal at an average cost of $.42 per
gallon at December 31, 1997 and December 31, 1996, respectively, at various
third-party storage facilities. At December 31, 1997, the Company had hedging
contracts in place for anticipated sales, consisting primarily of propane, at a
weighted average price of $.36 per gallon for approximately 3,200 MGal of the
stored NGLs in inventory.

The Company has been successful overall in replacing production with new
reserves. Historically, the Company has connected additional reserves that more
than offset production from reserves dedicated to existing facilities. However,
certain individual plants have experienced declines in dedicated reserves. In
1997, including the reserves associated with the Company's joint ventures and
partnerships, the Company connected new reserves to its gathering systems to
replace approximately 220% of 1997 production. On a Company-wide basis,
dedicated reserves increased from approximately 2.8 Tcf as of December 31, 1996
to approximately 3.3 Tcf at December 31, 1997.

In November 1996, the Company issued 6,325,000 shares of Common Stock at a
public offering price of $16.25 per share. The net proceeds to the Company of
$96.4 million were primarily used to reduce indebtedness under the Revolving
Credit Facility.

The Company has effective shelf registration statements filed with the
Securities and Exchange Commission for an aggregate of $200 million of debt
securities and preferred stock (along with the shares of common stock, if any,
into which such securities are convertible) and $62 million of debt securities,
preferred stock or common stock.

Risk Management Activities

The Company's commodity price risk management program has two primary
objectives. The first goal is to preserve and enhance the value of the Company's
equity volumes of gas and NGLs with regard to the impact of commodity price
movements on cash flow, net income and earnings per share in relation to those
anticipated by the Company's operating budget. The second goal is to manage
price risk related to the Company's physical gas, NGL and power marketing
activities to protect profit margins. This risk relates to hedging fixed price
purchase and sale commitments, preserving the value of storage inventories,
reducing exposure to physical market price volatility and providing risk
management services to a variety of customers.

The Company utilizes a combination of fixed price forward contracts, exchange-
traded futures and options, as well as fixed index swaps, basis swaps and
options traded in the over-the-counter ("OTC") market to accomplish these
objectives. These

20

instruments allow the Company to preserve value and protect margins because
gains or losses in the physical market are offset by corresponding losses or
gains in the value of the financial instruments.

The Company uses futures, swaps and options to reduce price risk and basis risk.
Basis is the difference in price between the physical commodity being hedged and
the price of the futures contract used for hedging. Basis risk is the risk that
an adverse change in the futures market will not be completely offset by an
equal and opposite change in the cash price of the commodity being hedged. Basis
risk exists in gas primarily due to the geographic price differentials between
cash market locations and futures contract delivery locations.

The Company enters into futures transactions on the New York Mercantile Exchange
("NYMEX") and the Kansas City Board of Trade and through OTC swaps and options
with creditworthy counterparties, consisting primarily of financial institutions
and other natural gas companies. The Company conducts its standard credit
review of OTC counterparties and has agreements with such parties that contain
collateral requirements. The Company generally uses standardized swap
agreements that allow for offset of positive and negative exposures. OTC
exposure is marked to market daily for the credit review process. The Company's
OTC credit risk exposure is partially limited by its ability to require a margin
deposit from its major counterparties based upon the mark-to-market value of
their net exposure. The Company is subject to margin deposit requirements under
these same agreements. In addition, the Company is subject to similar margin
deposit requirements for its NYMEX counterparties related to its net exposures.

The use of financial instruments may expose the Company to the risk of financial
loss in certain circumstances, including instances when (i) equity volumes are
less than expected, (ii) the Company's customers fail to purchase or deliver the
contracted quantities of natural gas or NGLs, or (iii) the Company's OTC
counterparties fail to perform. To the extent that the Company engages in
hedging activities, it may be prevented from realizing the benefits of favorable
price changes in the physical market. However, it is similarly insulated
against decreases in such prices.

As of December 31, 1997, the Company held a notional quantity of approximately
480 Bcf of natural gas futures, swaps and options, extending from January 1998
to December 1999 with a weighted average duration of approximately four months.
This was comprised of approximately 230 Bcf of long positions and 250 Bcf of
short positions in such instruments. As of December 31, 1997, the Company held a
notional quantity of approximately 148,000 MGal of NGL futures, swaps and
options, extending from January 1998 to December 1998 with a weighted average
duration of approximately five months. This was comprised of approximately
93,000 MGal of long positions and 55,000 MGal of short positions in such
instruments. As of December 31, 1996, the Company held a notional quantity of
approximately 250 Bcf of natural gas futures, swaps and options, extending from
January 1997 to October 1998 with a weighted average duration of approximately
four months. This was comprised of approximately 120 Bcf of long positions and
130 Bcf of short positions in such instruments. As of December 31, 1996, the
Company held a notional quantity of approximately 185,000 MGal of NGL futures,
swaps and options, extending from January 1997 to December 1997 with a weighted
average duration of approximately five months. This was comprised of
approximately 55,000 MGal of long positions and 130,000 MGal of short positions
in such instruments. As of December 31, 1997 and 1996, the Company did not have
any material hedging contracts in place associated with electric power.

The Company has hedged a portion of its equity volumes of gas and NGLs in 1998,
particularly in the first quarter, at pricing levels in excess of its 1998
operating budget. The Company's hedging strategy establishes a minimum and
maximum price to the Company while allowing market participation between these
levels. As of March 4, 1998, the Company had hedged approximately 75% of its
anticipated equity gas for 1998 at a weighted average NYMEX-equivalent minimum
price of $2.19 per Mcf, including approximately 85% of first quarter anticipated
equity volumes at a weighted average NYMEX-equivalent minimum price of $2.42 per
Mcf. Additionally, the Company has hedged approximately 25% of its anticipated
equity NGLs for 1998 at a weighted average composite Mont Belvieu and West Texas
Intermediate Crude-equivalent minimum price of $.40 per gallon ($16.75 per
barrel), including approximately 50% of first quarter anticipated equity volumes
at a weighted average composite Mont Belvieu and West Texas Intermediate Crude-
equivalent minimum price of $.36 per gallon ($15.20 per barrel).

At December 31, 1997, the Company had $512,000 of losses deferred in inventory
that will be recognized primarily during the first quarter of 1998 and are
expected to be offset by margins from the Company's related forward fixed price
hedges and physical sales. At December 31, 1997, the Company had unrecognized
net losses of $2.0 million related to financial instruments that are expected to
be offset by corresponding unrecognized net gains from the Company's obligations
to sell physical quantities of gas and NGLs.

21

During 1996, the Company began to enter into physical gas transactions payable
in Canadian dollars. The Company enters into forward purchases of Canadian
dollars from time to time to fix the cost of its future Canadian dollar
denominated natural gas purchase, storage and transportation obligations. This
is done to protect marketing margins from adverse changes in the U.S. and
Canadian dollar exchange rate between the time future payment obligation is made
and the actual payment date of such obligation. As of December 31, 1997 the
notional value of such contracts was approximately $5.5 million in Canadian
dollars. As of December 31, 1996, the notional value of such contracts was
immaterial.

The Company enters into speculative futures, swap and option trades on a very
limited basis for purposes that include testing of hedging techniques. The
Company's policies contain strict guidelines for such trading including
predetermined stop-loss requirements and net open positions limits. Speculative
futures, swap and option positions are marked to market at the end of each
accounting period and any gain or loss is recognized in income for that period.
Net gains from such speculative activities for the years ended December 31, 1997
and 1996 were not material.

Capital Investment Program

For the years ended December 31, 1997, 1996 and 1995 the Company expended $198.9
million, $74.6 million and $78.5 million, respectively, on new projects and
acquisitions. For the year ended December 31, 1997, the Company's expenditures
consisted of the following: (i) $133.2 million for new connects, system
expansions, the Bethel Treating facility and asset consolidations; (ii) $12.1
million for maintaining existing facilities; (iii) $49.3 for exploration and
production activities and acquisitions; (iv) $2.8 million related to the Katy
Facility; and (v) $1.5 million of miscellaneous expenditures.

Capital expenditures related to existing operations are expected to be
approximately $129.4 million during 1998, consisting of the following: capital
expenditures related to gathering, processing and pipeline assets are expected
to be approximately $84.8 million, of which approximately $74.8 million is
budgeted to be used for new connects, system expansions and asset consolidations
and approximately $10.0 million for maintaining existing facilities. The
Company expects capital expenditures on exploration and production activities,
the Katy Facility and miscellaneous items to be approximately $40.2 million,
$1.5 million and $2.9 million, respectively.

The Company has initiated a comprehensive review of its computer systems to
identify the systems that could be affected by the "Year 2000" issue and is in
the process of making the appropriate modifications to its computer systems.
The Company expects to incur internal staff costs as well as some consulting and
other expenses in order to prepare the systems for the year 2000. A portion of
these costs are not likely to be incremental costs to the Company, but rather
will represent costs which will be recorded as assets and depreciated.
Accordingly, the Company does not expect the amounts required to be expensed
over the next year to have a material effect on its results of operations.
Costs incurred during the year ended December 31, 1997 were immaterial. The
Company anticipates its Year 2000 conversion project to be completed in a timely
manner. However, there can be no assurance that the systems of other companies
on which the Company relies, will also be converted in a timely manner or that
any such failure to convert by another company would not have an adverse effect
on the Company. In order to minimize this impact, the Company is in contact
with its vendors and customers to work towards their compliance.

Financing Facilities

Revolving Credit Facility. The Company's unsecured variable rate
Revolving Credit Facility, was restated and amended on May 30, 1997. The
Revolving Credit Facility is with a syndicate of nine banks and provides for a
maximum borrowing commitment of $300 million, $156.5 million of which was
outstanding at December 31, 1997. The Revolving Credit Facility's commitment
period will terminate on March 31, 2002. At that time, any amounts outstanding
on the Revolving Credit Facility will become due and payable. The Revolving
Credit Facility bears interest at certain spreads over the Eurodollar rate, at
the Federal Funds rate plus .50%, or at the agent bank's prime rate. The Company
has the option to determine which rate will be used. The Company also pays a
facility fee on the commitment. The interest rate spreads and facility fee are
adjusted based on the Company's debt to capitalization ratio. At December 31,
1997, the spread was .35% over the Eurodollar rate and the facility fee was
.175%. The rate payable, including the facility fee, on the Revolving Credit
Facility at December 31, 1997 was 6.497%. The Company incurred approximately
$425,000 during 1997 of fees in association with the restatement and amendment;
such amounts were capitalized and will be amortized over the term of the
agreement. Pursuant to the Revolving Credit Facility, the Company is required to
maintain a debt to capitalization ratio (as defined therein) of not more than
60% as of the end of any fiscal quarter and a ratio of EBITDA (as defined
therein) to interest and dividends on preferred stock as of the end of any
fiscal quarter of not less than 2.75 to 1.0 through December 31, 1998, 3.0 to
1.0 from January 1, 1999

22

through December 31, 1999 and 3.25 to 1.0 thereafter. The Company generally
utilizes excess daily funds to reduce any outstanding balances on the Revolving
Credit Facility and associated interest expense and it intends to continue such
practice.

Master Shelf Agreement. In December 1991, the Company entered into a
Master Shelf Agreement (as amended and restated, the "Master Shelf") with The
Prudential Insurance Company of America ("Prudential"). The Master Shelf
Agreement, as further restated and amended, is fully utilized, as indicated in
the following table (000s):

Interest Final
Issue Date Amount Rate Maturity Principal Payments Due
- -------------------- -------- ----- ------------------ -----------------------------------------------

October 27, 1992 $25,000 7.51% October 27, 2000 $8,333 on each of October 27, 1998 through 2000
October 27, 1992 25,000 7.99% October 27, 2003 $8,333 on each of October 27, 2001 through 2003
September 22, 1993 25,000 6.77% September 22, 2003 single payment at maturity
December 27, 1993 25,000 7.23% December 27, 2003 single payment at maturity
October 27, 1994 25,000 9.05% October 27, 2001 single payment at maturity
October 27, 1994 25,000 9.24% October 27, 2004 single payment at maturity
July 28, 1995 50,000 7.61% July 28, 2007 $10,000 on each of July 28, 2003 through 2007
--------
$200,000
========

Pursuant to the Master Shelf Agreement, the Company is required to maintain a
current ratio (as defined therein) of at least 1.0 to 1.0, a minimum tangible
net worth equal to the sum of $345 million plus 50% of consolidated net earnings
earned from June 30, 1995 plus 75% of the net proceeds of any equity offerings
after June 30, 1995, a debt to capitalization ratio (as defined therein) of no
more than 55%, and an EBITDA (as defined therein) to interest ratio of not less
than 3.25 to 1.0 through October 31, 1997 and 3.75 to 1.0 thereafter. The
Company is prohibited from declaring or paying dividends on any capital stock on
or after June 30, 1995, that in the aggregate exceed the sum of $50 million plus
50% of consolidated net earnings earned after June 30, 1995, plus the cumulative
net proceeds received by the Company after June 30, 1995 from the sale of any
equity securities. At December 31, 1997, $118.5 million was available under
this limitation. The Company presently intends to finance the $8.3 million
payment due on October 27, 1998 with amounts available under the Revolving
Credit Facility.

Term Loan Facility. The Company also had a Term Loan Facility with four banks
which bore interest at 9.87% in 1997. In September 1997, the Company made the
final payment on the Term Loan Facility with amounts available under the
Revolving Credit Facility.

1993 Senior Notes. On April 28, 1993, the Company sold $50 million of 7.65%
Senior Notes ("1993 Senior Notes") due 2003 to a group of insurance companies.
Annual principal payments of $7.1 million on the 1993 Senior Notes were and are
due on April 30 of each year from 1997 through 2002, with any remaining
principal and interest outstanding due on April 30, 2003. The Company financed
the $7.1 million payment paid on April 30, 1997 with amounts available under the
Revolving Credit Facility. The Company presently intends to finance the $7.1
million payment due on April 30, 1998 with amounts available under the Revolving
Credit Facility. The 1993 Senior Notes are unsecured and contain certain
financial covenants that substantially conform with those contained in the
Master Shelf Agreement.

1995 Senior Notes. The Company sold $42 million of 1995 Senior Notes to a
group of insurance companies in the fourth quarter of 1995, with an interest
rate of 8.16% per annum and principal due in a single payment in December 2005.
The 1995 Senior Notes are unsecured and contain certain financial covenants that
conform with those contained in the Master Shelf Agreement.

Receivables Facility. In April 1995, the Company entered into an agreement
with Receivables Capital Corporation ("RCC"), as purchaser, and Bank of America
National Trust and Savings Association, as agent, pursuant to which the Company
could sell to RCC at face value on a revolving basis an undivided interest in
certain of the Company's trade receivables. Under the Receivables Facility, the
Company sold $75 million of trade receivables at a rate equal to RCC's
commercial paper rate plus .375%. Effective June 12, 1997, the Company elected
to terminate the facility. All amounts then outstanding were repaid with
amounts available under the Revolving Credit Facility.

Covenant Compliance. At December 31, 1997, the Company was in compliance with
all covenants in its loan agreements. Taking into account all the covenants
contained in the Company's financing facilities and maturities of long-term debt
during 1997, the Company had approximately $85 million of available borrowing
capacity at December 31, 1997. Historically, oil prices have been volatile and
subject to rapid price fluctuations. The oil and gas industry is currently
experiencing significantly declining oil prices. Such prices have declined
approximately 25% during the first quarter of 1998 to approximately $13.26 per
barrel as of March 16, 1998. In addition, the start-up volumes associated with
the Bethel Treating facility have been lower than anticipated. If the current
pricing of oil and associated NGLs continues or declines and volumes associated
with the Bethel Treating facility do not increase, the Company is uncertain as
to its ability to satisfy its interest coverage covenants under certain of its
debt agreements during the last half of 1998. However, the Company believes it
can obtain amendments or waivers from the necessary lenders.

23

ENVIRONMENTAL

The construction and operation of the Company's gathering lines, plants and
other facilities used for the gathering, transporting, processing, treating or
storing of gas and NGLs are subject to federal, state and local environmental
laws and regulations, including those that can impose obligations to clean up
hazardous substances at the Company's facilities or at facilities to which the
Company sends wastes for disposal. In most instances, the applicable regulatory
requirements relate to water and air pollution control or waste management. The
Company employs seven environmental engineers and six regulatory compliance
specialists to monitor environmental compliance and potential liabilities at its
facilities. Prior to consummating any major acquisition, the Company's
environmental engineers perform audits on the facilities to be acquired. In
addition, on an ongoing basis, the environmental engineers perform systematic
environmental assessments of the Company's existing facilities. The Company
believes that it is in substantial compliance with applicable material
environmental laws and regulations. Environmental regulation can increase the
cost of planning, designing, constructing and operating the Company's
facilities. The Company believes that the costs for compliance with current
environmental laws and regulations have not had and will not have a material
effect on the Company's financial position or results of operations.

In September 1997, the Texas Natural Resources Conservation Commission (the
"TNRCC"), which has authority to regulate, among other things, stationary air
emissions sources, created a committee to make recommendations to the TNRCC
regarding a voluntary emissions reduction plan for the permitting of existing
"grandfathered" air emissions sources within the State of Texas. A
"grandfathered" air emissions source is one that does not need a state operating
permit because it was constructed prior to 1971. The Company operates a number
of such sources within the State of Texas, including its Edgewood plant,
portions of its Midkiff plant and many of its compressors. The recommendations
proposed by the committee would create a voluntary permitting program for
grandfathered sources, including certain incentives to participate, such as the
ability to operate in such a source in a flexible manner. It is not clear which
of the committee's recommendations, if any, that the TNRCC will implement and it
is not possible to assess the potential effect on the Company until final
regulations are promulgated.

The Company anticipates that it is reasonably likely that the trend in
environmental legislation and regulation will continue to be towards stricter
standards. The Company is unaware of future environmental standards that are
reasonably likely to be adopted that will have a material effect on the
Company's financial position or results of operations, but it cannot rule out
that possibility.

The Company is in the process of voluntarily cleaning up substances at certain
facilities that it operates. The Company's expenditures for environmental
evaluation and remediation at existing facilities have not been significant in
relation to the results of operations of the Company and totaled approximately
$1.4 million for the year ended December 31, 1997, including approximately
$801,000 in air emissions fees to the states in which it operates. Although the
Company anticipates that such environmental expenses will increase over time,
the Company does not believe that such increases will have a material effect on
the Company's financial position or results of operations.

BUSINESS STRATEGY

The Company's four-part business plan is designed to increase profitability
through: (i) investing in projects that complement and extend its core gas
gathering, processing and marketing business; (ii) creating ventures with
producers who will dedicate additional acreage to the Company; (iii) expanding
its energy sales volumes by maximizing its asset base, firm transportation and
storage contracts and other contractual arrangements; and (iv) optimizing the
profitability of existing operations.

Expansion of Core Business

The Company continually evaluates investments in projects that meet its
objectives of complementing existing operations, expanding into new areas or
providing enhanced marketing opportunities. These projects typically include
gas gathering, treating, processing, transportation or storage assets, and NGL
product upgrade equipment. See further discussion in "Business and Properties -
Significant Acquisitions, Projects and Dispositions."

Increase Dedicated Acreage

The Company has entered and intends to continue to enter into agreements which
will provide it with new acreage to replace declines in reserves and generate
additional volumes for gathering and processing at its facilities and encourage
expansion into basins where the Company's facilities are located. The Company
believes that in order to secure additional gas supply for its facilities, it
must be willing to increase its participation in exploration and production
activities. However, the Company, where possible, has entered into agreements
with third parties to reduce a portion of the risk associated with exploration
and production activities. See further discussion in "Business and Properties -
Significant Acquisitions, Projects and Dispositions."

24

Expand Energy Marketing Services and Volumes

The Company is a full-service marketer primarily of gas and NGL products. The
Company focuses on the individual needs of its customers, primarily in the Rocky
Mountain region, and is committed to developing products and services that are
tailored to meet their requirements. The Company plans to expand its energy
marketing activities by: (i) maximizing profitability on volumes produced at the
Company's facilities; (ii) efficient use of various firm transportation and
storage contracts and other contractual arrangements to increase profitability
while limiting carrying risk; (iii) continuing to pursue higher-margin, end-use
markets, primarily in the Rocky Mountain region; and (iv) increasing third-party
gas and NGL sales volumes. The Company believes it competes effectively with
other marketers due to its national marketing presence and the marketing
information gained thereby, the services it provides and its physical asset
base.

Optimize Profitability

The Company seeks to optimize the profitability of its operations by: (i)
maintaining or increasing natural gas throughput levels; (ii) increasing its
efficiency through the consolidation of existing facilities; (iii) investing in
assets that enhance NGL value; (iv) selling non-strategic assets; and (v)
controlling operating and overhead expenses. In order to maximize its
competitive advantages, the Company continually monitors the economic
performance of each of its operating facilities to ensure that a desired cash
flow objective and operating efficiency is achieved.

25

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements

Western Gas Resources, Inc.'s Consolidated Financial Statements as of December
31, 1997 and 1996 and for each of the three years in the period ended December
31, 1997:

Page
----

Report of Management....................................... 27
Report of Independent Accountants.......................... 28
Consolidated Balance Sheets................................ 29
Consolidated Statement of Cash Flows....................... 30
Consolidated Statement of Operations....................... 31
Consolidated Statement of Changes in Stockholders' Equity.. 32
Notes to Consolidated Financial Statements................. 33

26

REPORT OF MANAGEMENT
--------------------

The financial statements and other financial information included in this Annual
Report on Form 10-K are the responsibility of Management. The financial
statements have been prepared in conformity with generally accepted accounting
principles appropriate in the circumstances and include amounts that are based
on Management's informed judgments and estimates.

Management relies on the Company's system of internal accounting controls to
provide reasonable assurance that assets are safeguarded and that transactions
are properly recorded and executed in accordance with Management's
authorization. The concept of reasonable assurance is based on the recognition
that there are inherent limitations in all systems of internal accounting
control and that the cost of such systems should not exceed the benefits to be
derived. The internal accounting controls, including internal audit, in place
during the periods presented are considered adequate to provide such assurance.

The Company's financial statements are audited by Price Waterhouse LLP,
independent accountants. Their report states that they have conducted their
audit in accordance with generally accepted auditing standards. These standards
include an evaluation of the system of internal accounting controls for the
purpose of establishing the scope of audit testing necessary to allow them to
render an independent professional opinion on the fairness of the Company's
financial statements.

Oversight of Management's financial reporting and internal accounting control
responsibilities is exercised by the Board of Directors, through an Audit
Committee that consists solely of outside directors. The Audit Committee meets
periodically with financial management, internal auditors and the independent
accountants to review how each is carrying out its responsibilities and to
discuss matters concerning auditing, internal accounting control and financial
reporting. The independent accountants and the Company's internal audit
department have free access to meet with the Audit Committee without Management
present.

Signature Title
- --------- -----

/S/ L. F. Outlaw
- ----------------
L. F. Outlaw President and Chief Operating Officer

/S/ William J. Krysiak
- ----------------------
William J. Krysiak Vice President - Finance (Principal
Financial and Accounting Officer)

27

REPORT OF INDEPENDENT ACCOUNTANTS
---------------------------------

To the Board of Directors and
Stockholders of Western Gas Resources, Inc.

In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of cash flows, of operations, and of changes in
stockholders' equity present fairly, in all material respects, the financial
position of Western Gas Resources, Inc. and its subsidiaries at December 31,
1997 and 1996, and the results of their cash flows and their operations for each
of the three years in the period ended December 31, 1997, in conformity with
generally accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.

As discussed in Note 2 to the financial statements, the Company changed its
method of accounting for the impairment of long-lived assets in 1995 to comply
with the provisions of Statement of Financial Accounting Standards No. 121.

PRICE WATERHOUSE LLP

Denver, Colorado
March 16, 1998

28

WESTERN GAS RESOURCES, INC.
CONSOLIDATED BALANCE SHEET
(000s, except share data)

December 31,
-----------------------
ASSETS 1997 1996
------ ---------- ----------

Current assets:
Cash and cash equivalents.................................................... $ 19,777 $ 39,504
Trade accounts receivable, net............................................... 258,791 338,708
Product inventory............................................................ 17,261 25,972
Parts inventory.............................................................. 9,405 2,599
Other........................................................................ 2,364 1,477
---------- ----------
Total current assets........................................................ 307,598 408,260
---------- ----------
Property and equipment:
Gas gathering, processing, storage and transmission.......................... 1,050,676 938,902
Oil and gas properties and equipment......................................... 136,129 144,732
Construction in progress..................................................... 64,268 35,250
---------- ----------
1,251,073 1,118,884
Less: Accumulated depreciation, depletion and amortization................... (294,350) (252,571)
---------- ----------
Total property and equipment, net........................................... 956,723 866,313
---------- ----------
Other assets:
Gas purchase contracts (net of accumulated amortization of $27,554 and
$24,552, respectively)...................................................... 43,687 46,689
Other........................................................................ 40,268 40,369
---------- ----------
Total other assets.......................................................... 83,955 87,058
---------- ----------
Total assets................................................................... $1,348,276 $1,361,631
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
Current liabilities:
Accounts payable............................................................. $ 326,696 $ 386,268
Accrued expenses............................................................. 27,151 28,670
Dividends payable............................................................ 4,217 4,215
---------- ----------

Total current liabilities................................................... 358,064 419,153
Long-term debt................................................................. 441,357 379,500
Deferred income taxes payable, net............................................. 80,743 82,511
---------- ----------
Total liabilities........................................................... 880,164 881,164
---------- ----------
Commitments and contingent liabilities......................................... - -
Stockholders' equity:
Preferred Stock; 10,000,000 shares authorized:
$2.28 cumulative preferred stock, par value $.10; 1,400,000 shares issued
($35,000,000 aggregate liquidation preference)............................ 140 140
$2.625 cumulative convertible preferred stock, par value $.10; 2,760,000
issued ($138,000,000 aggregate liquidation preference)..................... 276 276
Common stock, par value $.10; 100,000,000 shares authorized; 32,171,453 and
32,134,151 shares issued, respectively..................................... 3,217 3,213
Treasury stock, at cost; 25,016 shares in treasury........................... (788) (788)
Additional paid-in capital................................................... 399,554 397,061
Retained earnings............................................................ 66,999 82,378
Notes receivable from key employees secured by common stock.................. (1,286) (1,813)
---------- ----------
Total stockholders' equity.................................................. 468,112 480,467
---------- ----------
Total liabilities and stockholders' equity..................................... $1,348,276 $1,361,631
========== ==========

The accompanying notes are an integral part of the consolidated financial
statements.

29

WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(000s)

Year Ended December 31,
--------------------------------------
1997 1996 1995
----------- ------------ ----------

Reconciliation of net income to net cash provided by operating activities:
Net income (loss)........................................................... $ 1,487 $ 27,941 $ (6,108)
Add income items that do not affect cash:
Depreciation, depletion and amortization................................... 59,248 63,207 65,361
Deferred income taxes...................................................... 465 12,538 1,246
Distributions in excess of equity income, net.............................. 1,764 4,339 -
Gain on the sale of property and equipment................................. (4,681) (2,747) (939)
Loss on the impairment of property and equipment........................... 34,615 - 17,642
Other non-cash items, net.................................................. 3,250 336 (1,360)
----------- ----------- ---------
96,148 105,614 75,842
----------- ----------- ---------
Adjustments to working capital to arrive at net cash provided by
operating activities:
Decrease (increase) in trade accounts receivable........................... 79,963 (134,538) (69,982)
Decrease in product inventory.............................................. 7,480 2,115 22,985
Increase in parts inventory................................................ (6,806) (172) (136)
Increase in other current assets........................................... (1,027) (42) (157)
Decrease (increase) in other assets and liabilities, net................... 257 (733) (391)
(Decrease) increase in accounts payable.................................... (59,572) 186,758 54,269
(Decrease) increase in accrued expenses.................................... (1,688) 9,264 3,943
----------- ----------- ---------

Total adjustments......................................................... 18,607 62,652 10,531
----------- ----------- ---------
Net cash provided by operating activities................................... 114,755 168,266 86,373
----------- ----------- ---------
Cash flows from investing activities:
Purchases of property and equipment, including acquisitions................ (196,293) (74,203) (56,138)
Proceeds from the disposition of property and equipment.................... 20,034 7,656 13,328
Contributions to unconsolidated affiliates................................. (2,608) (352) (4,237)
Distribution from unconsolidated affiliates................................ - 1,500 -
Gas purchase contracts acquired............................................ - - (18,146)
----------- ----------- ---------
Net cash used in investing activities....................................... (178,867) (65,399) (65,193)
----------- ----------- ---------
Cash flows from financing activities:
Net proceeds from issuance of common stock................................. - 96,376 -
Net proceeds from exercise of common stock options......................... 239 62 117
Proceeds from issuance of long-term debt................................... - - 92,000
Payments on long-term debt................................................. (94,643) (12,500) (25,000)
Borrowings under revolving credit facility................................. 1,894,950 1,035,377 625,400
Payments on revolving credit facility...................................... (1,738,450) (1,172,877) (655,900)
Debt issue costs paid...................................................... (847) - (1,884)
Dividends paid............................................................. (16,864) (15,596) (16,796)
Redemption of preferred stock.............................................. - - (42,030)
----------- ----------- ---------
Net cash provided by (used in) financing activities......................... 44,385 (69,158) (24,093)
----------- ----------- ---------
Net (decrease) increase in cash............................................. (19,727) 33,709 (2,913)
Cash and cash equivalents at beginning of period............................ 39,504 5,795 8,708
----------- ----------- ---------
Cash and cash equivalents at end of period.................................. $ 19,777 $ 39,504 $ 5,795
=========== =========== =========

The accompanying notes are an integral part of the consolidated financial
statements.

30

WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
(000s, except share and per share amounts)

Year Ended December 31,
-----------------------------------------
1997 1996 1995
----------- ------------ ------------

Revenues:
Sale of gas............................................................ $ 1,657,479 $ 1,440,882 $ 876,399
Sale of natural gas liquids............................................ 611,969 561,581 331,760
Sale of electric power................................................. 59,477 30,667 -
Processing, transportation and storage revenue......................... 40,906 44,943 41,358
Other, net............................................................. 15,429 12,936 7,467
----------- ----------- -----------

Total revenues.................................................. 2,385,260 2,091,009 1,256,984
----------- ----------- -----------

Costs and expenses:
Product purchases...................................................... 2,146,430 1,844,151 1,040,265
Plant operating expense................................................ 78,113 73,116 71,030
Oil and gas exploration and production costs........................... 7,714 5,056 5,117
Depreciation, depletion and amortization............................... 59,248 63,207 65,361
Selling and administrative expense..................................... 29,446 29,411 26,610
Interest expense....................................................... 27,474 34,437 37,160
Restructuring charge................................................... - - 2,065
Loss on the impairment of property and equipment....................... 34,615 - 17,642
----------- ----------- -----------

Total costs and expenses.......................................... 2,383,040 2,049,378 1,265,250
----------- ----------- -----------

Income (loss) before income taxes........................................ 2,220 41,631 (8,266)

Provision (benefit) for income taxes:
Current........................................................... 268 1,152 (3,404)
Deferred.......................................................... 465 12,538 1,246
----------- ----------- -----------

Total provision (benefit) for income taxes........................ 733 13,690 (2,158)
----------- ----------- -----------

Net income (loss)........................................................ 1,487 27,941 (6,108)

Preferred stock requirements............................................. (10,439) (10,439) (15,431)
----------- ----------- -----------

Income (loss) attributable to common stock............................... $ (8,952) $ 17,502 $ (21,539)
=========== =========== ===========
Earnings (loss) per share of common stock................................ $(.28) $.66 $(.84)
=========== =========== ===========

Weighted average shares of common stock outstanding...................... 32,134,011 26,519,635 25,753,738
=========== =========== ===========

Earnings (loss) per share of common stock - assuming dilution............ $(.28) $.66 $(.84)
=========== =========== ===========

Weighted average shares of common stock outstanding - assuming dilution.. 32,137,803 26,541,565 25,788,955
=========== =========== ===========

The accompanying notes are an integral part of the consolidated financial
statements.

31

WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
(000s, except share amounts)

Shares of
7.25% 7.25%
Cumulative Shares of Cumulative
Senior Shares of $2.625 Senior
Perpetual $ 2.28 Cumulative Shares Perpetual $2.28
Convertible Cumulative Convertible Shares of Common Convertible Cumulative
Preferred Preferred Preferred of Common Stock Preferred Preferred
Stock Stock Stock Stock in Treasury Stock Stock
--------- --------- --------- ---------- ----------- --------- ---------

Balance at December 31, 1994.............. 400,000 1,400,000 2,760,000 25,712,301 25,016 $ 40 $ 140
Net loss, 1995............................ - - - - - - -
Stock options exercised................... - - - 57,411 - - -
Redemption of 7.25% cumulative senior.....
perpetual convertible preferred stock... (400,000) - - - - (40) -
Dividends declared on common stock........ - - - - - - -
Dividends declared on 7.25% cumulative....
senior perpetual convertible
preferred stock........................ - - - - - - -
Dividends declared on $2.28 cumulative....
preferred stock......................... - - - - - - -
Dividends declared on $2.625 cumulative...
convertible preferred stock............. - - - - - - -
--------- --------- --------- ---------- ----------- --------- ---------

Balance at December 31, 1995.............. - 1,400,000 2,760,000 25,769,712 25,016 - 140
Net income, 1996.......................... - - - - - - -
Stock options exercised................... - - - 14,423 - - -
Loans forgiven............................ - - - - - - -
Common stock offering..................... - - - 6,325,000 - - -
Dividends declared on common stock........ - - - - - - -
Dividends declared on $2.28 cumulative....
preferred stock........................ - - - - - - -
Dividends declared on $2.625 cumulative...
convertible preferred stock............. - - - - - - -
--------- --------- --------- ---------- ----------- --------- ---------

Balance at December 31, 1996.............. - 1,400,000 2,760,000 32,109,135 25,016 - 140
Net income, 1997.......................... - - - - - - -
Stock options exercised................... - - - 37,302 - - -
Tax benefit related to stock options...... - - - - - - -
Loans forgiven............................ - - - - - - -
Dividends declared on common stock........ - - - - - - -
Dividends declared on $2.28 cumulative....
preferred stock......................... - - - - - - -
Dividends declared on $2.625 cumulative...
convertible preferred stock............. - - - - - - -
--------- --------- --------- ---------- ----------- --------- ---------

Balance at December 31, 1997.............. - 1,400,000 2,760,000 32,146,437 25,016 $ - $ 140
========= ========= ========= ========== =========== ========= =========

$2.625
Cumulative Notes Total
Convertible Additional Receivable Stock-
Preferred Common Treasury Paid-In Retained from Key holder's
Stock Stock Stock Capital Earnings Employees Equity
--------- --------- --------- ---------- ----------- --------- ---------

Balance at December 31, 1994.............. $ 276 $ 2,574 $ (788) $ 338,926 $ 97,040 $ (1,525) $ 436,683
Net loss, 1995............................ - - - - (6,108) - (6,108)
Stock options exercised................... - 6 - 514 - (356) 164
Redemption of 7.25% cumulative senior.....
perpetual convertible preferred stock... - - - (38,206) (3,784) - (42,030)
Dividends declared on common stock........ - - - - (5,153) - (5,153)
Dividends declared on 7.25% cumulative....
senior perpetual convertible preferred..
stock................................... - - - - (1,208) - (1,208)
Dividends declared on $2.28 cumulative....
preferred stock......................... - - - - (3,194) - (3,194)
Dividends declared on $2.625 cumulative...
convertible preferred stock............. - - - - (7,245) - (7,245)
--------- --------- --------- ---------- ----------- --------- ---------

Balance at December 31, 1995.............. 276 2,580 (788) 301,234 70,348 (1,881) 371,909
Net income, 1996.......................... - - - - 27,941 - 27,941
Stock options exercised................... - 1 - 83 - (24) 60
Loans forgiven............................ - - - - - 92 92
Common stock offering..................... - 632 - 95,744 - - 96,376
Dividends declared on common stock........ - - - - (5,472) - (5,472)
Dividends declared on $2.28 cumulative....
preferred stock........................ - - - - (3,194) - (3,194)
Dividends declared on $2.625 cumulative...
convertible preferred stock............. - - - - (7,245) - (7,245)
--------- --------- --------- ---------- ----------- --------- ---------

Balance at December 31, 1996.............. 276 3,213 (788) 397,061 82,378 (1,813) 480,467
Net income, 1997.......................... - - - - 1,487 - 1,487
Stock options exercised................... - 4 - 260 - (25) 239
Tax benefit related to stock options...... - - - 2,233 - - 2,233
Loans forgiven............................ - - - - - 552 552
Dividends declared on common stock........ - - - - (6,427) - (6,427)
Dividends declared on $2.28 cumulative....
preferred stock......................... - - - - (3,194) - (3,194)
Dividends declared on $2.625 cumulative...
convertible preferred stock............. - - - - (7,245) - (7,245)
--------- --------- --------- ---------- ----------- --------- ---------

Balance at December 31, 1997.............. $ 276 $ 3,217 $ (788) $ 399,554 $ 66,999 $ (1,286) $ 468,112
========= ========= ========= ========== =========== ========= =========

The accompanying notes are an integral part of the
consolidated financial statements.

32

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - NATURE OF ORGANIZATION
- -------------------------------

Western Gas Resources, Inc. (the "Company") is an independent gas gatherer and
processor and energy marketer providing a full range of services to its
customers from the wellhead to the delivery point. The Company designs,
constructs, owns and operates natural gas gathering, processing, treating and
storage facilities in major gas-producing basins in the Rocky Mountain, Mid-
Continent, Gulf Coast and Southwestern regions of the United States. The
Company connects producers' wells to its gathering systems for delivery to its
processing or treating plants, processes the natural gas to extract natural gas
liquids ("NGLs") and treats the natural gas in order to meet pipeline
specifications. The Company markets gas and NGLs nationwide and in Canada,
providing risk management, storage, transportation, scheduling, peaking and
other services to a variety of customers. The Company explores and develops
certain producing properties, primarily in Wyoming, Louisiana and Texas, in
support of its existing facilities and to expand into new producing areas.

Western Gas Resources, Inc. was formed in October 1989 to acquire a majority
interest in Western Gas Processors, Ltd. (the "Partnership") and to assume the
duties of WGP Company, the general partner of the Partnership. The Partnership
was a Colorado limited partnership formed in 1977 to engage in the gathering and
processing of natural gas. The reorganization was accomplished in December 1989
through an exchange for common stock of partnership units held by the former
general partners of WGP Company and an initial public offering of Western Gas
Resources, Inc. Common Stock. On May 1, 1991, a further restructuring
("Restructuring") of the Partnership and Western Gas Resources, Inc. (together
with its predecessor, WGP Company, collectively, the "Company") was approved by
a vote of the security holders. The combinations were reorganizations of
entities under common control and were accounted for at historical cost in a
manner similar to poolings of interests.

The Company has completed three public offerings of Common Stock. In December
1989, the Company issued 3,527,500 shares of Common Stock at a public offering
price of $11.50. In November 1991, the Company issued 4,115,000 shares of
Common Stock at a public offering price of $18.375 per share. In November 1996,
the Company issued 6,325,000 shares of Common Stock at a public offering price
of $16.25 per share. The net proceeds to the Company from the November 1996
public offering of Common Stock of $96.4 million were primarily used to reduce
indebtedness under the Revolving Credit Facility.

The Company has also issued preferred stock in a private transaction and has
completed two public offerings of preferred stock. In October 1991, the Company
issued 400,000 shares of 7.25% Cumulative Senior Perpetual Convertible Preferred
Stock ("7.25% Preferred Stock") with a liquidation preference of $100 per share
to an institutional investor. In May 1995, the Company redeemed all of the
issued and outstanding shares of its 7.25% Preferred Stock pursuant to the
provisions of its Certificate of Designation relating to such preferred stock,
at an aggregate redemption price of approximately $42.0 million, including a
redemption premium of $2.0 million. In November 1992, the Company issued
1,400,000 shares of $2.28 Cumulative Preferred Stock with a liquidation
preference of $25 per share, at a public offering price of $25 per share,
redeemable at the Company's option on or after November 15, 1997. In February
1994, the Company issued 2,760,000 shares of $2.625 Cumulative Convertible
Preferred Stock with a liquidation preference of $50 per share, at a public
offering price of $50 per share, redeemable at the Company's option on or after
February 16, 1997 and convertible at the option of the holder into Common Stock
at a conversion price of $39.75.

SIGNIFICANT BUSINESS ACQUISITIONS, DISPOSITIONS AND PROJECTS

Coal Bed Methane

The Company is expanding its Powder River Basin coal bed methane natural gas
gathering system and developing its own coal seam gas reserves in Wyoming. The
Company has acquired drilling rights in the vicinity of known coal bed methane
production. During the years ended December 31, 1997 and 1996, the Company has
expended approximately $32.2 million and $6.9 million, respectively, on this
project. On October 30, 1997, the Company sold a 50% undivided interest in its
Powder River Basin coal bed methane gas operations. The final adjusted purchase
price was $17.9 million, resulting in a pre-tax gain of $4.7 million, which was
recognized in the fourth quarter of 1997. In January 1998, the Company acquired
an interest in approximately 25,000 acres. The Company's share of the purchase
price was $6.4 million and is subject to certain adjustments.

33

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Southwest Wyoming

The Company began to expand its gas gathering and exploration and production
activities in Southwest Wyoming during 1997. The expansion in this area is
primarily intended to develop acreage to replace declines in reserves and
generate additional volumes for gathering and processing at its facilities.
During the year ended December 31, 1997, the Company has expended approximately
$6.2 million on this project. In February 1998, the Company sold a 50%
undivided interest in a portion of the Granger gathering system for
approximately $4.0 million. This amount approximated the Company's cost in such
facilities.

Bethel Treating Facility (Cotton Valley Pinnacle Reef)

The Company is completing the construction of the Bethel Treating facility in
East Texas that gathers gas from the Cotton Valley Pinnacle Reef trend. The
Bethel Treating facility has been designed to accommodate incremental
expansions, depending upon the success of continued development in the trend.
Construction of the Bethel Treating facility began in September 1996. The
Bethel Treating facility, including the sulfur recovery plant, is expected to
cost approximately $97.0 million, of which approximately $90.5 million has been
expended since inception through December 31, 1997. As of December 31, 1997 a
portion of the Bethel Treating facility has been completed and placed in
service.

Midkiff/Benedum

During 1997, the Company expanded the capacity at its Midkiff/Benedum processing
plant to approximately 165 MMcf per day. The expansion was to accommodate
increased drilling activity by Pioneer Natural Resources Company and other
producers which supply natural gas to this facility. The Company's share of the
expansion cost was approximately $4.3 million.

Perkins

In November 1997, the Company entered into an agreement to sell its Perkins
facility. The sales price is $22.0 million, subject to certain adjustments, and
is expected to result in a pre-tax gain of approximately $11.0 million. The sale
is pending Federal Trade Commission approval. The Company expects to obtain such
approval and for the sale to close during the first quarter of 1998.

Northern Acquisition

In July 1995, the Company entered into an agreement to purchase eight West Texas
gathering systems, consisting of approximately 230 miles of gathering lines in
the Permian Basin, from Transwestern Gathering Company and Enron Permian
Gathering, Inc. The adjusted purchase price was $18.7 million.

Redman Smackover Joint Venture

Effective January 1, 1995, the Company entered into the Redman Smackover Joint
Venture ("Redman Smackover") agreement with various third parties. Redman
Smackover acquired working interests in three producing gas fields in East Texas
in the Smackover formation for an adjusted purchase price of $11.0 million.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- ---------------------------------------------------

The significant accounting policies followed by the Company and its wholly-owned
subsidiaries are presented here to assist the reader in evaluating the financial
information contained herein. The Company's accounting policies are in
accordance with generally accepted accounting principles.

34

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and
the Company's wholly owned subsidiaries. All material intercompany transactions
have been eliminated in consolidation. The Company's interest in certain
investments is accounted for by the equity method.

Inventories

For the year ended December 31, 1997, the cost of gas and NGL inventories is
determined by the weighted average cost on a location-by-location basis. Prior
to 1997, the cost of NGL inventories was determined by the last-in, first-out
(LIFO) method, on a location-by-location basis. The change in accounting method
from LIFO to weighted average cost was not material to any of the periods in the
three years ended December 31, 1997. As a result, prior year financial
statements were not restated. Residue and NGL inventory covered by hedging
contracts is accounted for on a specific identification basis. Product
inventory includes $11.9 million and $19.3 million of gas and $5.4 million and
$6.7 million of NGLs at December 31, 1997 and 1996, respectively. During the
year ended December 31, 1997, the Company recorded lower of cost or market
write-downs of NGL and gas inventories of $1.1 million and $129,000,
respectively.

Property and Equipment

Property and equipment is recorded at the lower of cost, including interest on
funds borrowed to finance the construction of new projects, or estimated
realizable value. Interest incurred during the construction period of new
projects is capitalized and amortized over the life of the associated assets.

Depreciation is provided using the straight-line method based on the estimated
useful life of each facility which ranges from three to 35 years. Useful lives
are determined based on the shorter of the life of the equipment or the reserves
serviced by the equipment. The cost of acquired gas purchase contracts is
amortized using the straight-line method.

Oil and Gas Properties and Equipment

The Company follows the successful efforts method of accounting for oil and gas
exploration and production activities. Acquisition costs, development costs and
successful exploration costs are capitalized. Exploratory dry hole costs, lease
rentals and geological and geophysical costs are charged to expense as incurred.
Upon surrender of undeveloped properties, the original cost is charged against
income. Producing properties and related equipment are depleted and depreciated
by the units-of-production method based on estimated proved reserves for
producing properties and proved developed reserves for lease and well equipment.
Revenues associated with such activities are reflected in sales of gas and NGLs
in the statement of operations.

Income Taxes

Deferred income taxes reflect the impact of temporary differences between
amounts of assets and liabilities for financial reporting purposes and such
amounts as measured by tax laws. These temporary differences are determined and
accounted for in accordance with Statement of Financial Accounting Standards
("SFAS") No. 109, "Accounting for Income Taxes."

Foreign Currency Adjustments

During the second quarter of 1997, the Company began operating a subsidiary in
Canada. The assets and liabilities associated with this subsidiary are
translated into U.S. dollars at the exchange rate as of the balance sheet date
and revenues and expenses at the weighted-average of exchange rates in effect
during each reporting period. SFAS No. 52, "Foreign Currency Translation,"
requires that cumulative translation adjustments be reported as a separate
component of stockholders' equity. Due to the limited operations of this
subsidiary, translation adjustments were immaterial for the year ended December
31, 1997 and as a result, separate disclosure of such adjustments is not made in
the Company's financial statements.

Revenue Recognition

Revenue for sales or services is recognized at the time the gas, NGLs or
electric power is delivered or at the time the service is performed.

35

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Comprehensive Income

In June 1997, the Financial Accounting Standards Board issued SFAS No. 130,
"Reporting Comprehensive Income," ("SFAS No. 130") effective for fiscal years
beginning after December 15, 1997. SFAS No. 130 requires that changes in items
which are required to be reported as a separate component of stockholders'
equity be reported in a separate financial statement. The Company's cumulative
translation adjustments would be required to be reported separately in
accordance with SFAS No. 130. However, as such adjustments were immaterial for
the year ended December 31, 1997, separate reporting of such adjustments is not
made in the Company's financial statements.

Gas, NGL and Electric Power Hedges

Gains and losses on hedges of product inventory are included in the carrying
amount of the inventory and are ultimately recognized in gas and NGL sales when
the related inventory is sold. Gains and losses related to qualifying hedges,
as defined by SFAS No. 80, "Accounting for Futures Contracts," of firm
commitments or anticipated transactions are recognized in gas, NGL and electric
power sales when the hedged physical transaction occurs. For purposes of the
Consolidated Statement of Cash Flows, all hedging gains and losses are
classified in net cash provided by operating activities.

Impairment of Long-Lived Assets

The Company adopted SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed of" ("SFAS No. 121"), which
requires that an impairment loss be recognized when the carrying amount of an
asset exceeds the fair market value or the expected future undiscounted net cash
flows. This test is to be performed at the lowest level at which cash flows can
be identified. Prior to October 1, 1995, the Company had performed this test
for its oil and gas producing properties on a Company-wide basis. Upon adoption
of SFAS No. 121, the Company reviewed its assets at the plant facility and oil
and gas producing property levels. SFAS No. 121 also requires long-lived assets
be reviewed whenever events or changes in circumstances indicate that the
carrying value of such assets may not be recoverable. In order to determine
whether an impairment exists, the Company compares its net book value of the
asset to the estimated fair market value or the undiscounted expected future
cash flows, determined by applying future prices estimated by management over
the shorter of the lives of the facilities or the reserves supporting the
facilities. If an impairment exists, write-downs of assets are based upon
expected cash flows discounted using an interest rate commensurate with the risk
associated with the underlying asset. The Company has written-down property and
equipment of $34.6 million and $17.6 million in accordance with SFAS No. 121
during the years ended December 31, 1997 and 1995, respectively.

Earnings (Loss) Per Share of Common Stock

In December 1997, the Company adopted SFAS No. 128, "Earnings per Share" ("SFAS
No. 128") which requires that earnings per share and earnings per share -
assuming dilution be calculated and presented on the face of the statement of
operations. In accordance with SFAS No. 128, earnings (loss) per share of
common stock is computed by dividing income (loss) attributable to common stock
by the weighted average shares of common stock outstanding. In addition,
earnings (loss) per share of common stock - assuming dilution is computed by
dividing income (loss) attributable to common stock by the weighted average
shares of common stock outstanding as adjusted for potential common shares.
Income (loss) attributable to common stock is income (loss) less preferred stock
dividends. The Company declared preferred stock dividends of $10.4 million,
$10.4 million and $11.6 million for the years ended December 31, 1997, 1996 and
1995, respectively. For the year ended December 31, 1995, loss attributable to
common stock was also reduced by a $2.0 million redemption premium and certain
up-front costs of $1.8 million paid on the 7.25% Preferred Stock. Common stock
options, which are potential common shares, had a dilutive effect on earnings
per share and increased the weighted average shares of common stock outstanding
by 3,792, 21,930 and 35,217 shares for the years ended December 31, 1997, 1996
and 1995, respectively. SFAS No. 128 dictates that the computation of earnings
per share shall not assume conversion, exercise or contingent issuance of
securities that would have an antidilutive effect on earnings (loss) per share.
As a result, the numerators and the denominators for the three years ended
December 31, 1997 are not adjusted to reflect the Company's $2.625 Cumulative
Convertible Preferred Stock outstanding. The shares are antidilutive as the
incremental shares result in an increase in earnings per share after giving
affect to the dividend requirements.

Concentration of Credit Risk

Financial instruments which potentially subject the Company to concentrations of
credit risk consist principally of trade accounts receivable and over-the-
counter ("OTC") swaps and options. The risk is limited due to the large number
of entities

36

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

comprising the Company's customer base and their dispersion across industries
and geographic locations. At December 31, 1997, the Company believes it had no
significant concentrations of credit risk.

Cash and Cash Equivalents

Cash and cash equivalents includes all cash balances and highly liquid
investments with an original maturity of three months or less.

Supplementary Cash Flow Information

Interest paid was $33.1 million, $36.7 million and $38.8 million, respectively,
for the years ended December 31, 1997, 1996 and 1995. Capitalized interest
associated with construction of new projects was $5.1 million, $1.7 million and
$1.5 million, respectively, for the years ended December 31, 1997, 1996 and
1995.

Income taxes paid were $2.6 million, $4.2 million and $1.6 million,
respectively, for the years ended December 31, 1997, 1996 and 1995.

Stock Compensation

The Financial Accounting Standards Board issued SFAS No. 123, "Accounting for
Stock-Based Compensation" ("SFAS No. 123"), effective for fiscal years
beginning after December 15, 1995. As permitted under SFAS No. 123, the Company
has elected to continue to measure compensation costs for stock-based employee
compensation plans as prescribed by Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees" ("APB No. 25"). The Company has
complied with the pro forma disclosure requirements of SFAS No. 123 as required
under the pronouncement.

The Company realizes an income tax benefit from the exercise of non-qualified
stock options related to the difference between the market price at the date of
exercise and the option price. APB No. 25 requires that this difference be
credited to additional paid-in capital. In September 1997, the Company recorded
a credit of $2.2 million to Additional Paid-In Capital to reflect such
difference associated with the Company's $5.40 Stock Option Plan.

Use of Estimates and Significant Risks

The preparation of consolidated financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the amounts reported in these financial statements
and accompanying notes. The more significant areas requiring the use of
estimates relate to oil and gas reserves, fair value of financial instruments,
future cash flows associated with assets and useful lives for depreciation,
depletion and amortization. Actual results could differ from those estimates.

The Company is subject to a number of risks inherent in the industry in which it
operates, primarily fluctuating prices and gas supply. The Company's financial
condition and results of operations will depend significantly upon the prices
received for gas and NGLs. These prices are subject to fluctuations in response
to changes in supply, market uncertainty and a variety of additional factors
that are beyond the control of the Company. In addition, the Company must
continually connect new wells to its gathering systems in order to maintain or
increase throughput levels to offset natural declines in dedicated volumes. The
number of new wells drilled will depend upon, among other factors, prices for
gas and oil, the energy policy of the federal government and the availability of
foreign oil and gas, none of which are within the Company's control.

Segment Reporting

In June 1997, the Financial Accounting Standards Board issued SFAS No. 131,
"Disclosure about Segments of an Enterprise and Related Information" ("SFAS No.
131"), effective for fiscal years beginning after December 15, 1997. Under SFAS
No. 131, the Company will be required to present certain information about
operating segments, including profit or loss and segment assets. The Company
will comply with the disclosure requirements of SFAS No. 131 as required under
the pronouncement.

37

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Reclassifications

Certain prior years' amounts in the consolidated financial statements and
related notes have been reclassified to conform to the presentation used in
1997.

NOTE 3 - RELATED PARTIES
- ------------------------

The Company enters into joint ventures and partnerships in order to reduce risk,
create strategic alliances and to establish itself in oil and gas producing
basins in the United States. For the years ended December 31, 1997, 1996 and
1995, the Company had a 50% ownership interest in the Williston Gas Company
("Williston"), Westana Gathering Company ("Westana") and Redman Smackover. The
Company acts as operator for Williston and Westana. The Company also has a 49%
interest in the Sandia Energy Resources Joint Venture ("Sandia"), which was
formed in March 1996. The Company's share of equity income or loss in these
ventures is reflected in Other net revenue. All transactions entered into by the
Company with its related parties are consummated in the ordinary course of
business.

Historically, the Company had purchased a significant portion of the production
of Williston. The Company also performed various operational and administrative
functions for Williston and charged a monthly overhead fee to cover such
services. In August 1996, substantially all of the assets associated with
Williston were sold to a third party. The Company expects that Williston will
be dissolved during 1998. At December 31, 1997, the Company's investment in
Williston was $348,000.

The Company performs various operational and administrative functions for
Westana and charges a monthly overhead fee to cover such services. The Company
records receivable and payable balances at the end of each accounting period
related to transactions with Westana and Redman Smackover. At December 31,
1997, the Company's investments in Westana and Redman Smackover were $26.2
million and $4.3 million, respectively.

The Company provides substantially all of the natural gas that Sandia markets
and also provides various administrative services to Sandia. In addition, the
Company purchases gas from Sandia. The Company records receivable and payable
balances at the end of each accounting period related to the above referenced
transactions. At December 31, 1997, the Company's investment in Sandia was
$347,000.

The following table summarizes account balances reflected in the financial
statements (000s):

As of or for the Year Ended December 31,
----------------------------------------
1997 1996 1995
------------ ------------ ------------

Trade accounts receivable.. $ 4,295 $ 5,552 $ 1,549
======= ======= =======

Accounts payable........... 7,246 11,041 4,979
======= ======= =======

Sales of gas and NGLs...... 19,504 10,592 -
======= ======= =======

Processing revenue......... 336 256 273
======= ======= =======

Product purchases.......... 59,082 57,675 28,196
======= ======= =======

Administrative expense..... $ 421 $ 419 $ 665
======= ======= =======

The Company has entered into agreements committing the Company to loan to
certain key employees an amount sufficient to exercise their options as each
portion of their options vests under the Key Employees' Incentive Stock Option
Plan and the $5.40 Stock Option Plan (See Note 10). The Company will forgive
the loan and accrued interest if the employee has been continuously employed by
the Company for periods specified under the agreements and Board of Directors'
resolutions. As

38

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

of December 31, 1997 and 1996, loans totaling $1.3 million and $1.8 million,
respectively, were outstanding to certain employees under these programs. The
loans are secured by a portion of the Common Stock issued upon exercise of the
options and are accounted for as a reduction of stockholders' equity. During
1997 and 1996, the Board of Directors approved the forgiveness of loans to
certain employees totaling approximately $552,000 and $92,000, respectively, in
connection with these plans.

NOTE 4 - RISK MANAGEMENT
- ------------------------

Gas, NGL and Electric Power Hedges

The Company's commodity price risk management program has two primary
objectives. The first goal is to preserve and enhance the value of the Company's
equity volumes of gas and NGLs with regard to the impact of commodity price
movements on cash flow, net income and earnings per share in relation to those
anticipated by the Company's operating budget. The second goal is to manage
price risk related to the Company's physical gas, NGL and power marketing
activities to protect profit margins. This risk relates to hedging fixed price
purchase and sale commitments, preserving the value of storage inventories,
reducing exposure to physical market price volatility and providing risk
management services to a variety of customers.

The Company utilizes a combination of fixed price forward contracts, exchange-
traded futures and options, as well as fixed index swaps, basis swaps and
options traded in the OTC market to accomplish these objectives. These
instruments allow the Company to preserve value and protect margins because
gains or losses in the physical market are offset by corresponding losses or
gains in the value of the financial instruments.

The Company uses futures, swaps and options to reduce price risk and basis risk.
Basis is the difference in price between the physical commodity being hedged and
the price of the futures contract used for hedging. Basis risk is the risk that
an adverse change in the futures market will not be completely offset by an
equal and opposite change in the cash price of the commodity being hedged. Basis
risk exists in gas primarily due to the geographic price differentials between
cash market locations and futures contract delivery locations.

The Company enters into futures transactions on the New York Mercantile Exchange
("NYMEX") and the Kansas City Board of Trade and through OTC swaps and options
with creditworthy counterparties, consisting primarily of financial institutions
and other natural gas companies. The Company conducts its standard credit
review of OTC counterparties and has agreements with such parties that contain
collateral requirements. The Company generally uses standardized swap
agreements that allow for offset of positive and negative exposures. OTC
exposure is marked to market daily for the credit review process. The Company's
OTC credit risk exposure is partially limited by its ability to require a margin
deposit from its major counterparties based upon the mark-to-market value of
their net exposure. The Company is subject to margin deposit requirements under
these same agreements. In addition, the Company is subject to similar margin
deposit requirements for its NYMEX counterparties related to its net exposures.

The use of financial instruments may expose the Company to the risk of financial
loss in certain circumstances, including instances when (i) equity volumes are
less than expected, (ii) the Company's customers fail to purchase or deliver the
contracted quantities of natural gas or NGLs, or (iii) the Company's OTC
counterparties fail to perform. To the extent that the Company engages in
hedging activities, it may be prevented from realizing the benefits of favorable
price changes in the physical market. However, it is similarly insulated
against decreases in such prices.

As of December 31, 1997, the Company held a notional quantity of approximately
480 Bcf of natural gas futures, swaps and options, extending from January 1998
to December 1999 with a weighted average duration of approximately four months.
This was comprised of approximately 230 Bcf of long positions and 250 Bcf of
short positions in such instruments. As of December 31, 1997, the Company held a
notional quantity of approximately 148,000 MGal of NGL futures, swaps and
options, extending from January 1998 to December 1998 with a weighted average
duration of approximately five months. This was comprised of approximately
93,000 MGal of long positions and 55,000 MGal of short positions in such
instruments. As of December 31,

39

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

1996, the Company held a notional quantity of approximately 250 Bcf of natural
gas futures, swaps and options, extending from January 1997 to October 1998 with
a weighted average duration of approximately four months. This was comprised of
approximately 120 Bcf of long positions and 130 Bcf of short positions in such
instruments. As of December 31, 1996, the Company held a notional quantity of
approximately 185,000 MGal of NGL futures, swaps and options, extending from
January 1997 to December 1997 with a weighted average duration of approximately
five months. This was comprised of approximately 55,000 MGal of long positions
and 130,000 MGal of short positions in such instruments. As of December 31, 1997
and 1996, the Company did not have any material hedging contracts in place
associated with electric power.

The Company has hedged a portion of its equity volumes of gas and NGLs in 1998,
particularly in the first quarter, at pricing levels in excess of its 1998
operating budget. The Company's hedging strategy establishes a minimum and
maximum price to the Company while allowing market participation between these
levels. As of March 4, 1998, the Company had hedged approximately 75% of its
anticipated equity gas for 1998 at a weighted average NYMEX-equivalent minimum
price of $2.19 per Mcf, including approximately 85% of first quarter anticipated
equity volumes at a weighted average NYMEX-equivalent minimum price of $2.42 per
Mcf. Additionally, the Company has hedged approximately 25% of its anticipated
equity NGLs for 1998 at a weighted average composite Mont Belvieu and West Texas
Intermediate Crude-equivalent minimum price of $.40 per gallon ($16.75 per
barrel), including approximately 50% of first quarter anticipated equity volumes
at a weighted average composite Mont Belvieu and West Texas Intermediate Crude-
equivalent minimum price of $.36 per gallon ($15.20 per barrel).

At December 31, 1997, the Company had $512,000 of losses deferred in inventory
that will be recognized primarily during the first quarter of 1998 and are
expected to be offset by margins from the Company's related forward fixed price
hedges and physical sales. At December 31, 1997, the Company had unrecognized
net losses of $2.0 million related to financial instruments that are expected to
be offset by corresponding unrecognized net gains from the Company's obligations
to sell physical quantities of gas and NGLs.

During 1996, the Company began to enter into physical gas transactions payable
in Canadian dollars. The Company enters into forward purchases of Canadian
dollars from time to time to fix the cost of its future Canadian dollar
denominated natural gas purchase, storage and transportation obligations. This
is done to protect marketing margins from adverse changes in the U.S. and
Canadian dollar exchange rate between the time future payment obligation is made
and the actual payment date of such obligation. As of December 31, 1997 the
notional value of such contracts was approximately $5.5 million in Canadian
dollars. As of December 31, 1996, the notional value of such contracts was
immaterial.

The Company enters into speculative futures, swap and option trades on a very
limited basis for purposes that include testing of hedging techniques. The
Company's policies contain strict guidelines for such trading including
predetermined stop-loss requirements and net open positions limits. Speculative
futures, swap and option positions are marked to market at the end of each
accounting period and any gain or loss is recognized in income for that period.
Net gains from such speculative activities for the years ended December 31, 1997
and 1996 were not material.

40

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

NOTE 5 - DEBT
- -------------

The following summarizes the Company's consolidated debt at the dates indicated
(000s):

December 31,
------------------
1997 1996
-------- --------

Master shelf and senior notes............ $284,857 $292,000
Variable rate revolving credit facility.. 156,500 -
Receivables facility..................... - 75,000
Bank term loan facility.................. - 12,500
-------- --------

Total long-term debt....... $441,357 $379,500
======== ========

Revolving Credit Facility. The Company's unsecured variable rate
Revolving Credit Facility, was restated and amended on May 30, 1997. The
Revolving Credit Facility is with a syndicate of nine banks and provides for a
maximum borrowing commitment of $300 million, $156.5 million of which was
outstanding at December 31, 1997. The Revolving Credit Facility's commitment
period will terminate on March 31, 2002. At that time, any amounts outstanding
on the Revolving Credit Facility will become due and payable. The Revolving
Credit Facility bears interest at certain spreads over the Eurodollar rate, at
the Federal Funds rate plus .50%, or at the agent bank's prime rate. The
Company has the option to determine which rate will be used. The Company also
pays a facility fee on the commitment. The interest rate spreads and facility
fee are adjusted based on the Company's debt to capitalization ratio. At
December 31, 1997, the spread was .35% over the Eurodollar rate and the facility
fee was .175%. The rate payable, including the facility fee, on the Revolving
Credit Facility at December 31, 1997 was 6.497%. The Company incurred
approximately $425,000 during 1997 of fees in association with the restatement
and amendment; such amounts were capitalized and will be amortized over the term
of the agreement. Pursuant to the Revolving Credit Facility, the Company is
required to maintain a debt to capitalization ratio (as defined therein) of not
more than 60% as of the end of any fiscal quarter and a ratio of EBITDA (as
defined therein) to interest and dividends on preferred stock as of the end of
any fiscal quarter of not less than 2.75 to 1.0 through December 31, 1998, 3.0
to 1.0 from January 1, 1999 through December 31, 1999 and 3.25 to 1.0
thereafter. The Company generally utilizes excess daily funds to reduce any
outstanding balances on the Revolving Credit Facility and associated interest
expense and it intends to continue such practice.

Master Shelf Agreement. In December 1991, the Company entered into a
Master Shelf Agreement (as amended and restated, the "Master Shelf") with The
Prudential Insurance Company of America ("Prudential"). The Master Shelf
Agreement, as further restated and amended, is fully utilized, as indicated in
the following table (000s):

Interest Final
Issue Date Amount Rate Maturity Principal Payments Due
- -------------------- -------- ----- ------------------ -----------------------------------------------

October 27, 1992 $25,000 7.51% October 27, 2000 $8,333 on each of October 27, 1998 through 2000
October 27, 1992 25,000 7.99% October 27, 2003 $8,333 on each of October 27, 2001 through 2003
September 22, 1993 25,000 6.77% September 22, 2003 single payment at maturity
December 27, 1993 25,000 7.23% December 27, 2003 single payment at maturity
October 27, 1994 25,000 9.05% October 27, 2001 single payment at maturity
October 27, 1994 25,000 9.24% October 27, 2004 single payment at maturity
July 28, 1995 50,000 7.61% July 28, 2007 $10,000 on each of July 28, 2003 through 2007
-------
$200,000
=======

Pursuant to the Master Shelf Agreement, the Company is required to maintain a
current ratio (as defined therein) of at least 1.0 to 1.0, a minimum tangible
net worth equal to the sum of $345 million plus 50% of consolidated net earnings
earned from June 30, 1995 plus 75% of the net proceeds of any equity offerings
after June 30, 1995, a debt to capitalization ratio (as defined therein) of no
more than 55%, and an EBITDA (as defined therein) to interest ratio of not less
than 3.25 to 1.0 through October 31, 1997 and 3.75 to 1.0 thereafter. The
Company is prohibited from declaring or paying dividends on any capital stock on

41

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

or after June 30, 1995, that in the aggregate exceed the sum of $50 million plus
50% of consolidated net earnings earned after June 30, 1995, plus the cumulative
net proceeds received by the Company after June 30, 1995 from the sale of any
equity securities. At December 31, 1997, $118.5 million was available under
this limitation. The Company presently intends to finance the $8.3 million
payment due on October 27, 1998 with amounts available under the Revolving
Credit Facility.

Term Loan Facility. The Company also had a Term Loan Facility with four banks
which bore interest at 9.87% in 1997. In September 1997, the Company made the
final payment on the Term Loan Facility with amounts available under the
Revolving Credit Facility.

1993 Senior Notes. On April 28, 1993, the Company sold $50 million of 7.65%
Senior Notes ("1993 Senior Notes") due 2003 to a group of insurance companies.
Annual principal payments of $7.1 million on the 1993 Senior Notes were and are
due on April 30 of each year from 1997 through 2002, with any remaining
principal and interest outstanding due on April 30, 2003. The Company financed
the $7.1 million payment paid on April 30, 1997 with amounts available under the
Revolving Credit Facility. The Company presently intends to finance the $7.1
million payment due on April 30, 1998 with amounts available under the Revolving
Credit Facility. The 1993 Senior Notes are unsecured and contain certain
financial covenants that substantially conform with those contained in the
Master Shelf Agreement.

1995 Senior Notes. The Company sold $42 million of 1995 Senior Notes to a
group of insurance companies in the fourth quarter of 1995, with an interest
rate of 8.16% per annum and principal due in a single payment in December 2005.
The 1995 Senior Notes are unsecured and contain certain financial covenants that
conform with those contained in the Master Shelf Agreement.

Receivables Facility. In April 1995, the Company entered into an agreement
with Receivables Capital Corporation ("RCC"), as purchaser, and Bank of America
National Trust and Savings Association, as agent, pursuant to which the Company
could sell to RCC at face value on a revolving basis an undivided interest in
certain of the Company's trade receivables. Under the Receivables Facility, the
Company sold $75 million of trade receivables at a rate equal to RCC's
commercial paper rate plus .375%. Effective June 12, 1997, the Company elected
to terminate the facility. All amounts then outstanding were repaid with
amounts available under the Revolving Credit Facility.

Covenant Compliance. At December 31, 1997, the Company was in compliance with
all covenants in its loan agreements. Taking into account all the covenants
contained in the Company's financing facilities and maturities of long-term debt
during 1997, the Company had approximately $85 million of available borrowing
capacity at December 31, 1997. Historically, oil prices have been volatile and
subject to rapid price fluctuations. The oil and gas industry is currently
experiencing significantly declining oil prices. Such prices have declined
approximately 25% during the first quarter of 1998 to approximately $13.26 per
barrel as of March 16, 1998. In addition, the start-up volumes associated with
the Bethel Treating facility have been lower than anticipated. If the current
pricing of oil and associated NGLs continues or declines and volumes associated
with the Bethel Treating facility do not increase, the Company is uncertain as
to its ability to satisfy its interest coverage covenants under certain of its
debt agreements during the last half of 1998. However, the Company believes it
can obtain amendments or waivers from the necessary lenders.

Approximate future maturities of long-term debt at the date indicated are as
follows at December 31, 1997 (000s):

1998......................... $ 15,476
1999......................... 15,476
2000......................... 15,477
2001......................... 40,476
2002......................... 171,976
Thereafter................... 182,476
--------

Total........................ $441,357
========

42

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

NOTE 6 - FINANCIAL INSTRUMENTS
- ------------------------------

The estimated fair values of the Company's financial instruments have been
determined by the Company using available market information and valuation
methodologies. Considerable judgment is required to develop the estimates of
fair value; thus, the estimates provided herein are not necessarily indicative
of the amount that the Company could realize upon the sale or refinancing of
such financial instruments.

December 31, 1997 December 31, 1996
------------------- -------------------
Carrying Fair Carrying Fair
Value Value Value Value
-------- --------- -------- ---------
(000s) (000s)

Cash and cash equivalents.. $ 19,777 $ 19,777 $ 39,504 $ 39,504
Trade accounts receivable.. 258,791 258,170 338,708 338,708
Accounts payable........... 326,696 326,696 386,268 386,268
Long-term debt............. 441,357 442,232 379,500 376,076
Risk management contracts.. $ - $ (2,189) $ - $(11,460)

The following methods and assumptions were used by the Company in estimating the
fair value of its financial instruments:

Cash and cash equivalents, trade accounts receivable and accounts payable
Due to the short-term nature of these instruments, the carrying value
approximates the fair value.

Long-term debt

The Company's long-term debt was primarily comprised of fixed rate facilities;
for this portion, fair market value was estimated using discounted cash flows
based upon the Company's current borrowing rates for debt with similar
maturities. The remaining portion of the long-term debt was borrowed on a
revolving basis which accrues interest at current rates; as a result, carrying
value approximates fair value of the outstanding debt.

Risk Management Contracts
Fair value represents the amount at which the instrument could be exchanged in
a current arms-length transaction.

NOTE 7 - INCOME TAXES
- ---------------------

The provision (benefit) for income taxes for the years ended December 31, 1997,
1996 and 1995 is comprised of (000s):

1997 1996 1995
----- ------- --------

Current:
Federal..................................... $ 268 $ 1,152 $(3,404)
State....................................... - - -
----- ------- -------

Total Current....................... 268 1,152 (3,404)
----- ------- -------

Deferred:
Federal..................................... 448 12,071 1,192
State....................................... 17 467 54
----- ------- -------

Total Deferred...................... 465 12,538 1,246
----- ------- -------

Total tax provision (benefit).. $ 733 $13,690 $(2,158)
===== ======= =======

43

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Temporary differences and carryforwards which give rise to the deferred tax
liabilities (assets) at December 31, 1997 and 1996 are as follows (000s):

1997 1996
--------- ---------

Property and equipment......................................... $158,258 $145,802
Differences between the book and tax basis of acquired assets.. 15,334 16,286
-------- --------

Total deferred income tax liabilities................... 173,592 162,088
-------- --------

Alternative Minimum Tax ("AMT") credit carryforwards........... (26,849) (26,581)
Net Operating Loss ("NOL") carryforwards....................... (66,000) (52,996)
-------- --------

Total deferred income tax assets........................ (92,849) (79,577)
-------- --------

Net deferred income taxes............................... $ 80,743 $ 82,511
======== ========

The change in the net deferred income taxes in 1997 includes a $2.2 million tax
benefit associated with the exercise of non-qualified stock options. The
Company expects to realize such tax benefit.

The differences between the provision (benefit) for income taxes at the
statutory rate and the actual provision (benefit) for income taxes for the years
ended December 31, 1997, 1996 and 1995 are summarized as follows (000s):

1997 % 1996 % 1995 %
------ ----- -------- ----- -------- ------

Income tax (benefit) at statutory rate...... $ 777 35.0 $14,570 35.0 $(2,893) (35.0)
State income taxes, net of federal
benefit.................................... 31 1.4 562 1.4 (99) (1.2)
Permanent differences on asset write-downs.. - - - - 1,173 14.2
Reduction of deferred income taxes to
reflect adjustment in acquired NOL
carryforward............................... - - (900) (2.2) - -
Adjustment to prior year income taxes....... - - (383) (.9) (300) (3.6)
Other....................................... (75) (3.4) (159) (.4) (39) (.5)
----- ---- ------- ---- ------- -----

Total...................................... $ 733 33.0 $13,690 32.9 $(2,158) (26.1)
===== ==== ======= ==== ======= =====

44

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

At December 31, 1997 the Company had NOL carryforwards for Federal and state
income tax purposes and AMT credit carryforwards for Federal income tax purposes
of approximately $181.6 million and $26.8 million, respectively. These
carryforwards expire as follows (000s):

Expiration Dates NOL AMT
----------------------------------- -------- -------
2003............................... $ 170 $ -
2004............................... 847 -
2005............................... 943 -
2006............................... 478 -
2007............................... 919 -
2008............................... 15,877 -
2009............................... 56,308 -
2010............................... 59,857 -
2011............................... 16,221 -
2012............................... 29,972 -
No expiration...................... - 26,849
-------- -------

Total........................... $181,592 $26,849
======== =======

The Company believes that the NOL carryforwards and AMT credit carryforwards
will be utilized prior to their expiration because they are substantially offset
by existing taxable temporary differences reversing within the carryforward
period or are expected to be realized by achieving future profitable operations
based on the Company's dedicated and owned reserves, past earnings history,
projections of future earnings and current assets.

45

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

NOTE 8 - COMMITMENTS AND CONTINGENT LIABILITIES
- ------------------------------------------------

JN Exploration and Production Litigation

JN Exploration and Production ("JN") is a producer of oil and natural gas that
sold unprocessed natural gas to the Company on a percentage-of-proceeds basis.
The Company processed the natural gas at its Teddy Roosevelt Plant, which is no
longer in operation. In JN Exploration and Production v. Western Gas Resources,
-------------------------------------------------------
Inc. United States District Court for the District of North Dakota,
- ----
Southwestern Division, Civil Action Nos. A1-93-53 and 903-CV-60, JN sued the
Company, alleging that JN was entitled to a portion of a $15 million amendment
fee the Company received in the years 1987 through 1989 from Williston Basin
Interstate Pipeline Company ("WBI"), which had an agreement with the Company to
purchase natural gas. On April 15, 1996, the Court issued a Memorandum and
Order granting JN's summary judgment motion on the issue of liability. On July
11, 1996, the Court issued a Memorandum and Order setting forth the manner in
which damages are to be calculated. On September 17, 1996, the Court entered a
final judgment against the Company in the amount of $421,000 (including pre-
judgment interest). The Company has filed a Notice of Appeal with the United
States Court of Appeals for the Eighth Circuit and an order granting a stay of
execution of the judgment until the appeal is resolved was granted by the Court
on November 29, 1996. The case has been briefed and argued to the Court and the
company is presently awaiting the Court's decision. The Company believes that
there are meritorious grounds to reverse the trial court's decision. One other
producer has filed a similar claim. If JN were to prevail on appeal, other
producers who sold natural gas which was processed at the Teddy Roosevelt Plant
during the time period in question may be able to assert similar claims. The
Company believes that it has meritorious defenses to such claims and, if sued,
the Company would defend vigorously against any such claims. At the present
time, it is not possible to predict the outcome of this litigation or any other
producer litigation that might raise similar issues or to estimate the amount of
potential damages.

Internal Revenue Service

The Internal Revenue Service ("IRS") has completed its examination of the
Company's returns for the years 1990 and 1991 and has proposed adjustments to
taxable income reflected in such returns that would shift the recognition of
certain items of income and expense from one year to another ("Timing
Adjustments"). To the extent taxable income in a prior year is increased by
proposed Timing Adjustments, taxable income may be reduced by a corresponding
amount in other years. However, the Company would incur an interest charge as a
result of such adjustment. The Company currently is protesting certain of these
proposed adjustments. In the opinion of management, any proposed adjustments
for the additional income taxes and interest that may result would not be
material. However, it is reasonably possible that the ultimate resolution could
result in an amount which differs materially from management's estimates.

Other

The Company is involved in various other litigation and administrative
proceedings arising in the normal course of business. In the opinion of
management, any liabilities that may result from these claims, will not,
individually or in the aggregate, have a material adverse effect on the
Company's financial position or results of operations.

NOTE 9 - EMPLOYEE BENEFIT PLANS
- -------------------------------

Profit Sharing Plan

A discretionary profit sharing plan (a defined contribution plan) exists for all
Company employees meeting certain service requirements. The Company may make
annual discretionary contributions to the plan as determined by the Board of
Directors

46

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

and provides for a match of 25% of employee contributions on the first
4% of employee compensation contributed. Contributions are made to
common/collective trusts for which Fidelity Management Trust Company acts as
trustee. The discretionary contributions by the Company were $1.9 million, $1.7
million and $1.3 million, for the years ended December 31, 1997 1996 and 1995,
respectively. The matching contributions were $310,000, $256,000 and $183,000
for the years ended December 31, 1997, 1996 and 1995, respectively.

Key Employees' Incentive Stock Option Plan and Non-employee Director Stock
Option Plan

Effective April 1987, the Board of Directors of the Company adopted a Key
Employees' Incentive Stock Option Plan ("Key Employee Plan") and a Non-Employee
Director Stock Option Plan ("Directors' Plan") that authorize the granting of
options to purchase 250,000 and 20,000 shares of the Company's Common Stock,
respectively. Under the plans, each of these options became exercisable as to
25% of the shares covered by it on the later of January 1, 1992 or one year from
the date of grant, subject to the continuation of the optionee's relationship
with the Company, and became exercisable as to an additional 25% of the covered
shares on the later of each subsequent January 1 through 1995 or on each
subsequent date of grant anniversary, subject to the same condition. Each of
these plans will terminate on the earlier of February 6, 2000 or the date on
which all options granted under each of the plans have been exercised in full.
The Company has entered into agreements committing the Company to loan certain
employees an amount sufficient to exercise their options as each portion of
their options vests. The Company will forgive such loans and associated accrued
interest if the employee has been continuously employed by the Company for four
years after the date of each loan increment. In January 1997, the Board of
Directors voted to extend the maturity for each of the loan increments by three
years for the first series of maturities and by two years for all other
maturities. During 1996, under the terms of a severance agreement, the Company
extended the maturity date of one former officer's loans to December 31, 2000.
In addition, under the terms of a severance agreement, the loans of a former
officer are being forgiven over the life of the original loan forgiveness
schedule. As of December 31, 1997 and 1996, loans related to 112,500 and
118,750 shares of Common Stock, respectively, totaling $1.2 million and $1.3
million, respectively, were outstanding under these terms.

1993 and 1997 Stock Option Plans

The 1993 Stock Option Plan ("1993 Plan") became effective on May 24, 1993 and
the 1997 Stock Option Plan ("1997 Plan") became effective on May 21, 1997 after
approvals by the Company's stockholders. Each plan is intended to be an
incentive stock option plan in accordance with the provisions of Section 422 of
the Internal Revenue Code of 1986, as amended. The Company has reserved
1,000,000 shares of Common Stock for issuance upon exercise of options under
each of the 1993 Plan and the 1997 Plan. The 1993 Plan and the 1997 Plan will
terminate on the earlier of March 28, 2003 and May 20, 2007, respectively, or
the date on which all options granted under each of the plans have been
exercised in full.

Under both of the plans, the Board of Directors of the Company determines and
designates from time to time those employees of the Company to whom options are
to be granted. If any option terminates or expires prior to being exercised,
the shares relating to such option are released and may be subject to reissuance
pursuant to a new option. The Board of Directors has the right to, among other
things, fix the price, terms and conditions for the grant or exercise of any
option. The purchase price of the stock under each option shall be the fair
market value of the stock at the time such option is granted. Under the 1993
Plan, options granted vest 20% each year on the anniversary of the date of grant
commencing with the first anniversary. Under the 1997 Plan, the Board of
Directors has the authority to set the vesting schedule from 20% per year to 33
1/3%. Under both plans, the employee must exercise the option within five years
of the date each portion vests.

$5.40 Stock Option Plan

In April 1987 and amended in February 1994, the Partnership adopted an employee
option plan ("$5.40 Plan") that authorized granting options to employees to
purchase 483,000 common units in the Partnership. Pursuant to the
Restructuring, the Company assumed the Partnership's obligation under the
employee option plan. The plan was amended upon the Restructuring to allow each
holder of existing options to exercise such options and acquire one share of
Common Stock for each common unit they were originally entitled to purchase.
The exercise price and all other terms and conditions for the exercise of such

47

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

options issued under the amended plan were the same as under the plan, except
that the Restructuring accelerated the time upon which certain options may be
exercised. All options under the plan were either exercised or forfeited on or
before May 31, 1997. The Company has entered into agreements committing the
Company to loan to certain employees an amount sufficient to exercise their
options, provided that the Company will not loan in excess of 25% of the total
amount available to the employee in any one year. In accordance with the
agreements, the Company forgave the majority of such loans and associated
accrued interest on July 2, 1997. Under the terms of a severance agreement, the
Company extended the maturity date of one former officer's loans to December 31,
2000. As of December 31, 1997 and 1996, loans related to 15,000 and 102,123
shares of Common Stock, respectively, totaling $81,000 and $551,000,
respectively, were outstanding under these terms.

The following table summarizes the number of stock options exercisable and
available for grant under the Company's benefit plans:

Key
Employee Directors'
$5.40 Plan Plan Plan 1993 Plan 1997 Plan
---------- ------ ------ --------- ----------

EXERCISABLE:
December 31, 1995.. 47,571 37,500 9,750 170,344 -
December 31, 1996.. 33,148 56,250 11,000 288,438 -
December 31, 1997.. - 75,000 12,250 448,171 -

AVAILABLE FOR GRANT:
December 31, 1995.. - 31,250 1,250 309,872 -
December 31, 1996.. - 31,250 1,250 4,734 -
December 31, 1997.. - 31,250 1,250 9,382 828,900

The following table summarizes the stock option activity under the Company's
benefit plans:

Number of Shares
Per Share -------------------------------------------------------------------
Price Key Employee Directors'
Range $5.40 Plan Plan Plan 1993 Plan 1997 Plan
--------------- ----------------- ------------- ---------- ---------- ---------

Balance 12/31/94 75,348 106,250 13,500 637,586 -
Granted................ $16.13 - $23.50 - - - 137,567 -
Exercised.............. 5.40 - 15.00 (26,161) (31,250) - - -
Forfeited or canceled.. 5.40 - 35.00 (1,616) - - (87,092) -
-------- ------- ---------- ------- ---------

Balance 12/31/95 47,571 75,000 13,500 688,061 -
Granted................ 13.88 - 18.63 - - - 351,733 -
Exercised.............. 5.40 (14,423) - - - -
Forfeited or canceled.. 13.25 - 35.00 - - - (46,595) -
-------- ------- ---------- ------- ---------

Balance 12/31/96 33,148 75,000 13,500 993,199 -
Granted................ 17.75 - 24.00 - - - 64,654 171,100
Exercised.............. 5.40 - 23.50 (32,077) - - (5,225) -
Forfeited or canceled.. $ 5.40 - $34.13 (1,071) - - (69,302) -
-------- ------- ---------- ------- ---------

Balance 12/31/97 - 75,000 13,500 983,326 171,100
======== ======= ========== ======= =========

48

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The following table summarizes the weighted average option exercise price
information under the Company's benefit plans:

Key
Employee Directors'
$5.40 Plan Plan Plan 1993 Plan 1997 Plan
---------- ------ ------ --------- ----------

Balance 12/31/94................. $5.40 $24.49 $14.13 $26.40 -
Granted................ - - - 20.68 -
Exercised.............. 5.40 10.71 - - -
Forfeited or canceled.. 5.40 - - 27.53 -
Balance 12/31/95................. 5.40 30.23 14.13 25.11 -
Granted................ - - - 14.63 -
Exercised.............. 5.40 - - - -
Forfeited or canceled.. - - - 27.05 -
Balance 12/31/96................. 5.40 30.23 14.13 21.31 -
Granted................ - - - 19.71 19.63
Exercised.............. 5.40 - - 16.91 -
Forfeited or canceled.. 5.40 - - 25.54 -
Balance 12/31/97................. $ - $30.23 $14.13 $20.93 $19.63

SFAS No. 123 encourages companies to record compensation expense for stock-based
compensation plans at fair value. As permitted under SFAS No. 123, the Company
has elected to continue to measure compensation costs for such plans as
prescribed by APB No. 25. SFAS No. 123 requires pro forma disclosures for each
year a statement of operations is presented. Such information was only
calculated for the options granted under the 1993 Plan and the 1997 Plan as
there were no grants under any other plans. The weighted average fair value of
options granted under the 1993 Plan of $10.54, $10.18 and $6.03 for the years
ended December 31, 1997, 1996 and 1995, respectively, and the weighted average
fair value of options granted under the 1997 Plan of $12.66 was estimated using
the Black-Scholes option-pricing model with the following assumptions:

1993 Plan 1997 Plan
------------------------------ ----------
1997 1996 1995 1997
---------- ------ ---------- ------

Risk-free interest rate......... 6.1% 6.35% 5.65% 6.1%
Expected life (in years)........ 6 7 8 10
Expected volatility............. 42% 37% 32% 42%
Expected dividends (quarterly).. $ .05 $ .05 $ .05 $ .05

Had compensation expense for the Company's 1997, 1996 and 1995 grants for stock-
based compensation plans been determined consistent with the fair value method
under SFAS No. 123, the Company's net income (loss), income (loss) attributable
to common stock, earnings (loss) per share of common stock and earnings (loss)
per share of common stock - assuming dilution would approximate the pro forma
amounts below (000s, except per share amounts):

1997 1996 1995
------------ ----------- ---------
As Reported Pro forma As Reported Pro forma As Reported Pro forma
------------ ---------- ----------- --------- ------------ ----------

Net income (loss).................... $ 1,487 $ 941 $27,941 $27,891 $ (6,108) $ (6,108)
Net income (loss) attributable to
common stock................ (8,952) (9,498) 17,502 17,452 (21,539) (21,539)
Earnings (loss) per share of common
stock....................... $ (.28) $ (.30) $ .66 $ .66 $ (.84) $ (.84)
Earnings (loss) per share of common
stock - assuming dilution.. $ (.28) $ (.30) $ .66 $ .66 $ (.84) $ (.84)

49

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The 1993 Plan dictates that the options granted vest 20% each year on the
anniversary of the date of grant commencing with the first anniversary. The
Board of Directors has the authority to set the vesting schedule from 20% per
year to 33 1/3% for the 1997 Plan. All options granted in 1997 will vest at the
rate of 20% per year. As a result, no compensation expense, as defined under
SFAS No. 123, is recognized in the year options are granted. In addition, the
fair market value of the options at grant date is amortized over this vesting
period for purposes of calculating compensation expense. In the initial years
of implementation of SFAS No. 123, the pro forma compensation expense will not
be representative of future pro forma expense.

NOTE 10 - SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
- ----------------------------------------------------------------------
(UNAUDITED):
- ------------

Costs

The following tables set forth capitalized costs at December 31, 1997, 1996 and
1995 and costs incurred for oil and gas producing activities for the years ended
December 31, 1997, 1996 and 1995 (000s):

1997 1996 1995
--------- --------- ---------

Capitalized costs:
Proved properties......................................... $134,102 $140,871 $136,499
Unproved properties....................................... 18,464 8,064 6,279
-------- -------- --------

Total............................................................ 152,566 148,935 142,778
Less accumulated depletion................................ (61,766) (58,548) (46,792)
-------- -------- --------

Net capitalized costs............................................ $ 90,800 $ 90,387 $ 95,986
======== ======== ========

The Company's share of Redman Smackover's net capitalized costs.. $ 3,845 $ 4,385 $ 5,216
======== ======== ========

Costs incurred:
Acquisition of properties
Proved.................................................... $ 7,499 $ 242 $ 1,591
Unproved.................................................. 10,457 909 128
Development costs................................................ 13,134 3,893 3,035
Exploration costs................................................ 1,322 2,581 1,102
-------- -------- --------

Total costs incurred............................................. $ 32,412 $ 7,625 $ 5,856
======== ======== ========

The Company's share of Redman Smackover's costs incurred......... $ 236 $ 8 $ 5,540
======== ======== ========

50

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Results of Operations

The results of operations for oil and gas producing activities, excluding
corporate overhead and interest costs, for the years ended December 31, 1997,
1996 and 1995 are as follows (000s):

1997 1996 1995
--------- --------- ---------

Revenues from sale of oil and gas:
Sales.......................................... $ 5,970 $ 1,821 $ 2,490
Transfers...................................... 25,571 31,733 29,739
-------- -------- --------
Total........................................ 31,541 33,554 32,229

Production costs...................................... (6,900) (4,256) (4,160)
Exploration costs..................................... (1,439) (898) (956)
Depreciation, depletion and amortization.............. (11,549) (11,756) (15,081)
Impairment of oil and gas properties.................. (19,615) - -
Income tax benefit (expense).......................... 2,986 (6,261) (4,429)
-------- -------- --------

Results of operations................................. $ (4,976) $ 10,383 $ 7,603
======== ======== ========

The Company's share of Redman Smackover's operations.. $ 1,265 $ 1,745 $ 324
======== ======== ========

Reserve Quantity Information

Reserve estimates are subject to numerous uncertainties inherent in the
estimation of quantities of proved reserves and in the projection of future
rates of production and the timing of development expenditures. The accuracy of
such estimates is a function of the quality of available data and of engineering
and geological interpretation and judgment. Estimates of economically
recoverable reserves and of future net cash flows expected therefrom prepared by
different engineers or by the same engineers at different times may vary
substantially. Results of subsequent drilling, testing and production may cause
either upward or downward revisions of previous estimates. Further, the volumes
considered to be commercially recoverable fluctuate with changes in commodity
prices and operating costs. Any significant revision of reserve estimates could
materially adversely affect the Company's financial condition and results of
operations.

51

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The following table sets forth information for the years ended December 31,
1997, 1996 and 1995 with respect to changes in the Company's proved reserves,
all of which are in the United States. The Company has no significant
undeveloped reserves.

Natural Crude
Gas Oil
(MMcf) (MBbls)
-------- -------

Proved reserves:

December 31, 1994.................................... 134,541 478
Revisions of previous estimates...................... (8,846) 437
Production........................................... (16,875) (200)
------- ----

December 31, 1995.................................... 108,820 715
Revisions of previous estimates...................... (2,147) 286
Purchases of reserves in place....................... 2,372 -
Production........................................... (13,014) (158)
------- ----

December 31, 1996.................................... 96,031 843
Revisions of previous estimates...................... (18,132) (74)
Extensions and discoveries........................... 113,251 191
Purchases of reserves in place....................... 34,588 -
Production........................................... (13,142) (154)
------- ----

December 31, 1997.................................... 212,596 806
======= ====

The Company's share of Redman Smackover's proved reserves:
December 31, 1995.................................... 12,647 -
======= ====
December 31, 1996.................................... 10,811 -
======= ====
December 31, 1997.................................... 10,218 -
======= ====

Standardized Measures of Discounted Future Net Cash Flows

Estimated discounted future net cash flows and changes therein were determined
in accordance with SFAS No. 69, "Disclosures about Oil and Gas Producing
Activities." Certain information concerning the assumptions used in computing
the valuation of proved reserves and their inherent limitations are discussed
below. The Company believes such information is essential for a proper
understanding and assessment of the data presented.

Future cash inflows are computed by applying year end prices of oil and gas
relating to the Company's proved reserves to the year end quantities of those
reserves. Future price changes are considered only to the extent provided by
contractual arrangements, including futures contracts, in existence at year end.

The assumptions used to compute estimated future net revenues do not necessarily
reflect the Company's expectations of actual revenues or costs, nor their
present worth. In addition, variations from the expected production rate also
could result directly or indirectly from factors outside of the Company's
control, such as unintentional delays in development, changes in prices or
regulatory controls. The reserve valuation further assumes that all reserves
will be disposed of by production. However, if reserves are sold in place,
additional economic considerations could also affect the amount of cash
eventually realized.

52

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Future development and production costs are computed by estimating the
expenditures to be incurred in developing and producing the proved oil and gas
reserves at the end of the year, based on year end costs and assuming
continuation of existing economic conditions.

Future income tax expenses are computed by applying the appropriate year end
statutory tax rates, with consideration of future tax rates already legislated,
to the future pretax net cash flows relating to the Company's proved oil and gas
reserves. Permanent differences in oil and gas-related tax credits and
allowances are recognized.

An annual discount rate of 10% was used to reflect the timing of the future net
cash flows relating to proved oil and gas reserves.

Information with respect to the Company's estimated discounted future cash flows
from its oil and gas properties for the years ended December 31, 1997, 1996 and
1995 is as follows (000s):

1997 1996 1995
---------- ---------- ---------

Future cash inflows................................................................. $ 352,491 $ 305,095 $230,986
Future production costs............................................................. (118,056) (54,306) (52,442)
Future development costs............................................................ (28,803) (1,728) (3,564)
Future income tax expense........................................................... (32,614) (37,870) (18,386)
--------- --------- --------
Future net cash flows............................................................... 173,018 211,191 156,594
10% annual discount for estimated timing of cash flows.............................. (73,445) (100,474) (74,832)
--------- --------- --------
Standardized measure of discounted future net cash flows relating to
proved oil and gas reserves............................................... $ 99,573 $ 110,717 $ 81,762
========= ========= ========

The Company's share of Redman Smackover's standardized measure of
discounted future net cash flows relating to proved oil and gas reserves.. $ 6,326 $ 5,684 $ 4,665
========= ========= ========

Principal changes in the Company's estimated discounted future net cash flows
for the years ended December 31, 1997, 1996 and 1995 are as follows (000s):

1997 1996 1995
-------------- ---------------- -------------

January 1.............................................. $ 110,717 $ 81,762 $ 95,731
Sales and transfers of oil and gas produced, net of
production costs.................................... (24,650) (29,298) (28,069)
Net changes in prices and production costs related
to future production................................ (168,927) 61,888 10,788
Development costs incurred during the period......... 13,134 3,893 3,035
Changes in estimated future development costs........ (27,075) (2,057) 2,631
Changes in extensions and discoveries................ 171,109 - -
Revisions of previous quantity estimates............. (31,597) 2,554 (12,147)
Purchases of reserves in place....................... 50,148 5,266 -
Accretion of discount................................ 11,072 8,176 9,573
Net change in income taxes........................... (5,255) (19,484) (1,603)
Other, net........................................... 897 (1,983) 1,823
---------- -------- --------

December 31............................................ $ 99,573 $110,717 $ 81,762
========== ======== ========

53

WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

NOTE 11 - QUARTERLY RESULTS OF OPERATIONS (UNAUDITED):
- ------------------------------------------------------

The following summarizes certain quarterly results of operations (000s, except
per share amounts):

Earnings (Loss)
Per Share of
Net Earnings (Loss) Common Stock -
Operating Gross Income Per Share of Assuming
Revenues Profit (a) (Loss) Common Stock Dilution
---------- ---------- --------- --------------- ----------------

1997 quarter ended:
March 31.............................................. $ 635,538 $ 30,847 $10,608 $ .25 $ .25
June 30............................................... 463,575 15,508 878 (.05) (.05)
September 30.......................................... 555,888 20,757 4,997 .07 .07
December 31........................................... 730,259 26,643 (14,996)(b) (.55) (.55)
---------- -------- -------- ----- -----
$2,358,260 $ 93,755 $ 1,487 $(.28) $(.28)
========== ======== ======= ===== =====

1996 quarter ended:
March 31.............................................. $ 480,714 $ 33,223 $10,233 $ .30 $ .30
June 30............................................... 446,223 24,029 5,432 .11 .11
September 30.......................................... 467,721 19,275 2,881 .01 .01
December 31........................................... 696,351 28,952 9,395 .24 .24
---------- -------- ------- ----- -----
$2,091,009 $105,479 $27,941 $ .66 $ .66
========== ======== ======= ===== =====

(a) Excludes selling and administrative, interest and income tax expenses and
loss on the impairment of property and equipment.

(b) Includes an after-tax, non-cash expense resulting from the evaluation of
property and equipment in accordance with SFAS No. 121 of $34.6 million.

54

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

ITEM 11. EXECUTIVE COMPENSATION

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Pursuant to instruction G(3) to Form 10-K, Items 10, 11, 12 and 13 are omitted
because the Company will file a definitive proxy statement (the "Proxy
Statement") pursuant to Regulation 14A under the Securities Exchange Act of 1934
not later than 120 days after the close of the fiscal year. The information
required by such Items will be included in the definitive proxy statement to be
so filed for the Company's annual meeting of stockholders scheduled for May 22,
1998 and is hereby incorporated by reference.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a) The following documents are filed as part of this report:

(1) Financial Statements:

Reference is made to page 23 for a list of all financial statements
filed as a part of this report.

(2) Financial Statement Schedules:

None required.

(3) Exhibits:

3.1 Certificate of Incorporation of Western Gas Resources, Inc. (Filed as
exhibit 3.1 to Western Gas Resources, Inc.'s Registration Statement
on Form S-1, Registration No. 33-31604 and incorporated herein by
reference).

3.2 Certificate of Amendment to the Certificate of Incorporation of
Western Gas Resources, Inc. (Filed as exhibit 3.2 to Western Gas
Resources, Inc.'s Registration Statement on Form S-1, Registration
No. 33-31604 and incorporated herein by reference).

3.3 Certificate of Designation of 7.25% Cumulative Senior Perpetual
Convertible Preferred Stock of the Company (Filed as exhibit 3.5 to
Western Gas Resources, Inc.'s Registration Statement on Form S-1,
Registration No. 33-43077 dated November 14, 1991 and incorporated
herein by reference).

3.4 Certificate of Designation of $2.28 Cumulative Preferred Stock of the
Company. (Filed as exhibit 3.6 to Western Gas Resources, Inc.'s
Registration Statement of Form S-1, Registration No. 33-53786 dated
November 12, 1992 and incorporated herein by reference).

55

3.5 Certificate of Designation of the $2.625 Cumulative Convertible
Preferred Stock of the Company (Filed under cover of Form 8-K
dated February 24, 1994 and incorporated herein by reference).

3.6 Amended and restated of the By-laws of Western Gas Resources, Inc.
as adopted by the Board of Directors on September 6, 1996. (Filed
as exhibit 3.9 to Western Gas Resources, Inc.'s Form 10-Q for the
nine months ended September 30, 1996 and incorporated herein by
reference).

3.7 Amendment of the Bylaws of Western Gas Resources, Inc. adopted by
the Board of Directors on March 21, 1997. (Filed as exhibit 3.7 to
Western Gas Resources, Inc.'s Form 10-Q for the three months ended
March 31, 1997 and incorporated herein by reference).

10.1 Restated Profit-Sharing Plan and Trust Agreement of Western Gas
Resources, Inc. (Filed as exhibit 10.8 to Western Gas Resources,
Inc.'s Registration Statement on Form S-4, Registration No. 33-
39588 dated March 27, 1991 and incorporated herein by reference).

10.2 Western Gas Resources, Inc. Key Employees' Incentive Stock Option
Plan (Filed as exhibit 10.13 to Western Gas Resources, Inc.'s
Registration Statement on Form S-4, Registration No. 33-39588
dated March 27, 1991 and incorporated herein by reference).

10.3 Registration Rights Agreement among Western Gas Resources, Inc.,
WGP, Inc., Heetco, Inc., NV, Dean Phillips, Inc., Sauvage Gas
Company and Sauvage Gas Service, Inc. (Filed as exhibit 10.14 to
Western Gas Resources, Inc.'s Registration Statement on Form S-4,
Registration No. 33-39588 dated March 27, 1991 and incorporated
herein by reference).

10.4 Amendment No. 1 to Registration Rights Agreement as of May 1, 1991
between Western Gas Resources, Inc., Bill Sanderson, WGP, Inc.,
Dean Phillips, Inc., Heetco, Inc., NV, Sauvage Gas Company and
Sauvage Gas Service, Inc. (Filed as exhibit 4.2 to Western Gas
Resources, Inc.'s Form 10-Q for the quarter ended June 30, 1991
and incorporated herein by reference).

10.5 Second Amendment and First Restatement of Western Gas Processors,
Ltd. Employees' Common Units Option Plan (Filed as exhibit 10.6 to
Western Gas Resources, Inc.'s Registration Statement on Form S-1,
Registration No. 33-43077 dated November 14, 1991 and incorporated
herein by reference).

10.6 Agreement to provide loans to exercise key employees' common stock
options (Filed as exhibit 10.26 to Western Gas Resources, Inc.'s
Annual Report on Form 10-K for the fiscal year ended December 31,
1991 and incorporated herein by reference).

10.7 Agreement to provide loans to exercise employees' common stock
options (Filed as exhibit 10.27 to Western Gas Resources, Inc.'s
Annual Report on Form 10-K for the fiscal year ended December 31,
1991 and incorporated herein by reference).

10.8 Note Purchase Agreement (without exhibits) dated as of April 1,
1993 by and between the Company and the Purchasers for
$50,000,000, 7.65% Senior Notes Due April 30, 2003 (Filed as
exhibit 10.48 to Western Gas Resources Inc.'s Form 10-Q for the
six months ended June 30, 1993 and incorporated herein by
reference).

10.9 General Partnership Agreement (without exhibits), dated August 10,
1993 for Westana Gathering Company by and between Western Gas
Resources -Oklahoma, Inc. (a subsidiary of the Company) and
Panhandle Gathering Company (Filed as exhibit 10.50 to Western Gas
Resources Inc.'s Form 10-Q for the six months ended June 30, 1993
and incorporated herein by reference).

10.10 Amendment to General Partnership Agreement dated August 10, 1993
by and between Western Gas Resources -Oklahoma, Inc. (a subsidiary
of the Company) and Panhandle Gathering Company (Filed as exhibit
10.51 to Western Gas Resources Inc.'s Form 10-Q for the six months
ended June 30, 1993 and incorporated herein by reference).

56

10.11 Amendment No. 1 to Note Purchase Agreement dated as of August 31,
1993 by and among the Company and the Purchasers (Filed as exhibit
10.61 to Western Gas Resources Inc.'s Form 10-Q for the nine
months ended September 30, 1993 and incorporated herein by
reference).

10.12 Amendment No. 2 to Note Purchase Agreement dated as of August 31,
1994 by and among Western Gas Resources, Inc. and the Purchasers.
(Filed as exhibit 10.68 to Western Gas Resources, Inc.'s Form 10-Q
for the nine months ended September 30, 1994 and incorporated
herein by reference).

10.13 Amendment No. 3 to Note Purchase Agreement as of March 22, 1995 by
and among Western Gas Resources, Inc. and the Purchasers.(Filed as
exhibit 10.38 to Western Gas Resources, Inc.'s Form 10-Q for the
three months ended March 31, 1995 and incorporated herein by
reference).

10.14 Form of Employment Agreement by and between Western Gas Resources,
Inc. and certain Executive Officers. (Filed as exhibit 10.40 to
Western Gas Resources, Inc.'s Form 10-Q for the three months ended
March 31, 1995 and incorporated herein by reference).

10.15 Joint Venture Agreement of Redman Smackover Joint Venture. (Filed
as exhibit 10.42 to Western Gas Resources, Inc.'s Form 10-Q for
the six months ended June 30, 1995 and incorporated herein by
reference).

57

10.16 Amendment No. 4 to Note Purchase Agreements as of July 14, 1995 by
and among Western Gas Resources, Inc. and the Purchasers. (Filed
as exhibit 10.43 to Western Gas Resources, Inc.'s Form 10-Q for
the six months ended June 30, 1995 and incorporated herein by
reference).

10.17 Second Amended and Restated Master Shelf Agreement effective
January 31, 1996 by and between Western Gas Resources, Inc. and
Prudential Company of America. (Filed as exhibit 10.49 to Western
Gas Resources, Inc.'s Form 10-K for the year ended December 31,
1995 and incorporated herein by reference).

10.18 Fourth Amendment to First Restated Loan Agreement (Revolver) dated
November 29, 1995 by and among Western Gas Resources, Inc. and
NationsBank, as agent, and the Lenders. (Filed as exhibit 10.51 to
Western Gas Resources, Inc.'s Form 10-K for the year ended
December 31, 1995 and incorporated herein by reference).

10.19 Senior Note Purchase Agreement dated November 29, 1995 by and
among Western Gas Resources, Inc. and the Purchasers identified
therein. (Filed as exhibit 10.52 to Western Gas Resources, Inc.'s
Form 10-K for the year ended December 31, 1995 and incorporated
herein by reference).

58

10.20 Loan Agreement dated May 30, 1997 among Western Gas Resources,
Inc. and NationsBank of Texas, N.A. as Agent, Bank of America
National Trust and Savings Association as Co-agent and Certain
Banks as Lenders (Revolver). (Filed as exhibit 10.40 to Western
Gas Resources, Inc.'s Form 10-Q for the six months ended June 30,
1996 and incorporated herein by reference).

11.1 Statement regarding computation of per share earnings.

21.1 List of Subsidiaries of Western Gas Resources, Inc.

23.1 Consent of Price Waterhouse LLP, independent accountants.

(b) Reports on Form 8-K:

A report on Form 8-K was filed on November 18, 1997 to notify the Securities
and Exchange Commission and the Company's stockholders of agreements between
the Company and Ultra Resources, Inc. and RIS Resources (USA) Inc.

(c) Exhibits required by Item 601 of Regulation S-K. See (a) (3) above.

59

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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, in the City of Denver,
State of Colorado on March 16, 1998.

WESTERN GAS RESOURCES, INC.
---------------------------
(Registrant)

By: /s/ Brion G. Wise
---------------------------------
Brion G. Wise
Chairman of the Board and
Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.

/s/ Brion G. Wise Chairman of the Board, Chief Executive March 16, 1998
- ----------------------------------- Officer and Director
Brion G. Wise

/s/ Walter L. Stonehocker Vice Chairman of the Board and Director March 16, 1998
- -----------------------------------
Walter L. Stonehocker

/s/ Bill M. Sanderson Director March 16, 1998
- -----------------------------------
Bill M. Sanderson

/s/ Richard B. Robinson Director March 16, 1998
- -----------------------------------
Richard B. Robinson

/s/ Dean Phillips Director March 16, 1998
- -----------------------------------
Dean Phillips

Director March 16, 1998
- -----------------------------------
Ward Sauvage

/s/ James A. Senty Director March 16, 1998
- -----------------------------------
James A. Senty

Director March 16, 1998
- -----------------------------------
Joseph E. Reid

/s/ William J. Krysiak Vice President - Finance (Principal March 16, 1998
- ----------------------------------- Financial and Accounting Officer)
William J. Krysiak

60