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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, 2000 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
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)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of exchange on which registered
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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 March 1, 2001 was $823,237,419.
The number of shares outstanding of the only class of the registrant's common
stock, as of March 1, 2001 was 32,410,922.
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 18, 2001.
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 .................................................................. 6
Gas Gathering, Processing, and Transportation.......................................... 7
Significant Acquisitions, Projects and Dispositions.................................... 8
Producing Properties................................................................... 11
Marketing.............................................................................. 12
Environmental.......................................................................... 14
Competition............................................................................ 14
Regulation............................................................................. 15
Employees.............................................................................. 15
3. Legal Proceedings.......................................................................... 15
4. Submission of Matters to a Vote of Security Holders........................................ 15
II. 5. Market for Registrant's Common Equity and Related Stockholder Matters...................... 16
6. Selected Financial Data.................................................................... 17
7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.................................................................. 19
8. Financial Statements and Supplementary Data................................................ 29
9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure................................................................... 58
III. 10. Directors and Executive Officers of the Registrant......................................... 58
11. Executive Compensation..................................................................... 58
12. Security Ownership of Certain Beneficial Owners and Management............................. 58
13. Certain Relationships and Related Transactions............................................. 58
IV. 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K........................... 58
2
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
The terms "Western," "we," "us" and "our" as used in this Form 10-K refer
to Western Gas Resources, Inc. and its subsidiaries as a consolidated entity,
except where it is clear that these terms mean only Western Gas Resources, Inc.
General
Western gathers, processes, treats, develops and produces, transports and
markets natural gas and natural gas liquids, NGLs. We operate in major gas-
producing basins in the Rocky Mountain, Mid-Continent, Gulf Coast and
Southwestern regions of the United States. We design, construct, own and operate
natural gas gathering and processing facilities in order to provide our
customers with a broad range of services from the wellhead to the sales delivery
point. We also develop and produce natural gas reserves.
Our operations are conducted through the following four business segments:
. Gathering and Processing--Our operations are in well-established basins
such as the Permian, Anadarko, Powder River, Green River and San Juan
basins. We connect oil and gas wells to our gathering systems for
delivery to our processing or treating plants. At our plants we
process natural gas to extract NGLs and we treat natural gas in order
to meet pipeline specifications. We provide these services to major
oil and gas companies and to independent producers.
. Production--We develop and explore for natural gas primarily to enhance
and support our existing gathering and processing operations. We sell
the natural gas that we produce to third parties. Our producing
properties are primarily located in the Powder River and Green River
basins of Wyoming.
. Marketing--We buy and sell natural gas and NGLs in the wholesale market
in the United States and in Canada. We provide transportation,
scheduling, peaking and other services to our customers. Our
customers for these services include utilities, local distribution
companies, industrial end-users and other energy marketers.
. Transportation--We transport natural gas through our regulated
pipelines for producers and energy marketers under fee schedules
regulated by state or federal agencies.
Historically, we have derived over 95% of our revenues from the sale of gas
and NGLs. Our revenues by type of operation are as follows (dollars in
thousands):
Year Ended December 31,
---------------------------------------------------------------
2000 % 1999 % 1998 %
------------ ----- ------------ ----- ------------ -----
Sale of gas........................................... $ 2,624,409 80.0 $ 1,501,066 78.6 $ 1,611,521 76.1
Sale of NGLs.......................................... 590,932 18.0 346,819 18.1 449,696 21.3
Processing, transportation and storage revenues....... 53,156 1.6 48,994 2.6 44,743 2.1
Other, net ........................................... 13,491 .4 13,845 .7 11,128 .5
------------ ----- ------------ ----- ------------ -----
$ 3,281,988 100.0 $ 1,910,724 100.0 $ 2,117,088 100.0
============ ===== ============ ===== ============ =====
In order to reduce our overall debt level and provide us with additional
liquidity to fund our key growth projects and invest in new growth
opportunities, we have sold several non-strategic assets. During 1999 and 2000,
we sold our Katy, Giddings, MiVida, Black Lake and Arkoma facilities, our
wholly-owned subsidiary in California and we contracted for the sale of our
wholly-owned subsidiary Pinnacle Gas Treating, Inc. Including the sale of
Pinnacle which closed in January 2001, we have received $230.9 million in net
sale proceeds which were used to reduce our outstanding debt. Primarily as a
result of these sales, our total debt was reduced from $504.9 million at
December 31, 1998 to $358.7 million at December 31, 2000. The sales of these
facilities reduced operating and administrative costs and allow us to focus on
our core areas in which we have substantial operations. In 2001, we are thus
better positioned to pursue projects including consolidations and acquisitions
with future growth potential.
3
Business Strategy. In 1998 and 1999, as oil and gas prices were approaching
historical lows, our activities were focused on consolidating our businesses in
our core operating regions and reducing our outstanding debt. Higher product
prices throughout 2000 and continuing into 2001 along with our improved
financial position allow us to emphasize the growth aspects of our business
strategy. Our long-term business plan is to increase our profitability by: (i)
optimizing the efficiency and utilization of our existing operations; (ii)
developing natural gas reserves and increasing production volumes on our
existing acreage positions; and (iii) investing in projects or acquiring assets
that complement and extend our core natural gas gathering, processing,
production and marketing businesses.
With our improved financial position, in 2001, we will actively evaluate
acquisitions of either assets or companies. These acquisitions can be related to
gathering and processing or production with emphasis on properties located in
the Rocky Mountains or Canada. Capital expenditures budgeted for existing
operations in 2001 are approximately $136.4 million. This includes approximately
$71.8 million related to gathering, processing and pipeline assets and
approximately $46.8 million for the acquisition of undeveloped acreage and
development of gas reserves in the Powder River basin. This budget will be
increased to provide for acquisitions if approved by our board of directors.
Optimize Profitability. We continuously seek to improve the profitability
of our existing operations by:
. increasing natural gas throughput levels through new well connections
and expansion of gathering systems. Our operations are located in
some of the most actively drilled oil and gas producing basins in the
United States. We enter into agreements under which we gather and
process natural gas produced on acreage dedicated to us by third
parties. We contract for production from new wells and newly
dedicated acreage in order to replace declines in existing reserves
or increase reserves that are dedicated for gathering and processing
at our facilities. At December 31, 2000, our estimated dedicated
reserves totaled 2.7 Tcf. In 2000, including the reserves developed
by us and associated with our partnerships and excluding the reserves
and production associated with the facilities sold during this
period, we connected new reserves to our facilities to replace
approximately 222% of throughput. In order to obtain additional
dedicated acreage and to secure contracts on favorable terms, we may
participate to a limited extent with third-party producers in
exploration and production activities that supply our facilities. For
the same reason, we may also offer to sell ownership interests in our
facilities to selected producers. In 2000, we spent approximately
$49.7 million on additional well connections and compression and
gathering system expansions including acquisitions. We increased
throughput levels at our facilities from 895 MMcf/D in 1993 to 1,411
MMcf/D in 2000.
. increasing our efficiency by modernization of equipment and the
consolidation of existing facilities. Replacing and upgrading field
equipment allows us to minimize maintenance costs, fuel consumption
and field operating costs. For example, in the fourth quarter of 2000
we replaced older compression at our Midkiff facility with newer,
fuel efficient equipment. This upgrade has resulted in lower
maintenance costs and a decrease in our fuel consumption which
increases the natural gas available for sale. We will continue
upgrading compression in this area throughout 2001 and anticipate
spending approximately $20.3 million on this project. Consolidations
allow us to increase the throughput of one facility while reducing
the operating costs of the consolidated assets. For example, the
acquisition of the remaining 50% interest in the Westana Gathering
Company in the first quarter of 2000 and the acquisition of the
remaining 28% interest in the Lincoln Road facility in the fourth
quarter allowed us the opportunity to consolidate our operations in
these areas and improve our operating efficiencies.
. evaluating assets. We routinely review the economic performance of
each of our operating facilities to ensure that a targeted rate of
return is achieved. If an operating facility is not generating
targeted returns we will explore various options, such as
consolidation with other Western-owned or third-party-owned
facilities, dismantlement, asset swap or sale.
. controlling operating and overhead expenses. We continually evaluate
our operations for methods to improve our operating costs. For
example, in 2000, we replaced many of our dry flow wellhead meters
with electronic flow meters. Electronic flow meters reduce costs and
increase the accuracy of volumetric information by electronically
transmitting data to our central offices.
Developing Natural Gas Reserves. We selectively participate in exploration
and production activities, in part, to secure additional gas supply for our
facilities. Beginning in 1997, we substantially increased our investment in the
acquisition of
4
undeveloped acreage and development of the Powder River coal bed methane gas. We
have acquired drilling rights on approximately 530,000 net acres in the basin.
At December 31, 2000, we have proved developed and undeveloped reserves of
approximately 350 Bcf on a portion of this acreage position. We have
participated in the development of properties in southwest Wyoming and Colorado.
These properties have an additional 58 Bcf of proved developed and undeveloped
reserves. In total this represents an increase of approximately 50% in our
proved reserves from December 31, 1999. We also estimate a net total of 1.9 Tcf
of probable reserves on an unaudited and unrisked basis associated with
undeveloped acreage in these areas. There can be no assurance, however, as to
the ultimate recovery of these probable reserves. We will also consider
investing in other exploration and production prospects that we consider to be
low risk and complementary to our other business segments.
Expansion of Core Business. We will invest in projects that complement and
extend our core natural gas gathering, processing, production and marketing
businesses. We may also expand our gathering, processing and production
operations into new geographic areas. In 2001, we consider ourselves better
positioned to pursue projects including consolidations and acquisitions with
future growth potential. During 2000, the majority of our capital budget was
spent in the Powder River basin of Wyoming and in southwest Wyoming. These
projects included:
. drilling 950 gross wells in the Powder River basin coal bed methane
area to increase natural gas production and throughput at our
existing gathering and transportation facilities and
. continued expansion of our gathering systems and participation in the
drilling for additional natural gas reserves in southwest Wyoming.
This section, as well as other sections in this Form 10-K, contains
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 our gathering operations, our project development
schedules, our budgeted capital expenditures, success of our drilling
activities, our marketing plans and anticipated volumes through our facilities
and from production activities 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 with acreage dedicated to our facilities. In addition
to the important factors referred to herein, numerous other factors affecting
our business generally and in the markets for gas and NGLs in which we
participate, could cause actual results to differ materially from our
projections in this Form 10-K. 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."
Our principal offices are located at 12200 North Pecos Street, Denver,
Colorado 80234-3439, and our telephone number is (303) 452-5603. Western Gas
Resources, Inc. was incorporated in Delaware in 1989.
5
Principal Facilities
The following tables provide information concerning our principal
facilities at December 31, 2000. We also own and operate several smaller
treating, processing and transportation facilities located in the same areas as
our other facilities.
Average for the Year Ended
December 31, 2000
Gas Gas --------------------------------------------
Gathering Throughput Gas Gas NGL
Year Placed System Capacity Throughput Production Production
Plant Facilities (1) In Service Miles(2) (MMcf/D)(3) (MMcf/D)(4) (MMcf/D)(5) (MGal/D)(5)
- ------------------------------------ ---------- -------- ----------- ----------- ----------- -----------
Texas
Bethel Treating (6)(17)........... 1997 86 300 189 184 -
Gomez Treating (6)................ 1971 385 280 113 103 -
Midkiff/Benedum................... 1949 2,183 165 147 94 901
Mitchell Puckett Gathering (6).... 1972 91 120 95 62 1
Louisiana
Toca (7)(8)....................... 1958 - 160 123 117 99
Wyoming
Coal Bed Methane
Gathering (15).................. 1990 444 223 212 196 -
Fort Union Gas Gathering (6)(15).. 1999 106 435 164 164 -
Granger (7)(9)(10)................ 1987 483 235 142 120 349
Hilight Complex (7)............... 1969 626 80 18 13 59
Kitty/Amos Draw (7)............... 1969 314 17 12 8 46
Lincoln Road (10) ................ 1988 149 50 20 19 22
Newcastle (7)..................... 1981 146 5 3 2 18
Red Desert (7).................... 1979 111 42 14 13 25
Reno Junction (9)................. 1991 - - - - 91
Oklahoma
Arkoma (16)....................... 1985 76 12 7 6 -
Chaney Dell ...................... 1966 2,058 130 56 46 172
Westana (14)...................... 1981 926 45 66 50 102
New Mexico
San Juan River (6)................ 1955 140 60 28 20 33
Utah
Four Corners Gathering............ 1988 104 15 2 2 13
------- ------- ------ ------ ------
Total........................... 8,428 2,374 1,411 1,219 1,931
======= ======= ====== ====== ======
Average for the Year Ended
December 31, 2000
-----------------
Pipeline Gas
Year Placed Transportation Capacity Throughput
Transportation Facilities (1) In Service Miles(2) (MMcf/D)(2) (MMcf/D)(4)
- --------------------------------- ---------- -------------- ----------- -----------
MIGC (11)(13).................... 1970 245 130 175
MGTC (12)........................ 1963 252 18 12
------- ----- -------
Total......................... 497 148 187
======= ===== =======
Footnotes on following page.
6
(1) Our interest in all facilities is 100% except for Midkiff/Benedum (73%);
Newcastle (50%) and Fort Union gathering system (13%). We operate all
facilities and all data includes our interests and the interests of other
joint interest owners and producers of gas volumes dedicated to the
facility. Unless otherwise indicated, all facilities shown in the table
are gathering and processing facilities.
(2) Gas gathering system miles, transportation miles and pipeline capacity
are as of December 31, 2000.
(3) Gas throughput capacity is as of December 31, 2000 and represents
capacity in accordance with design specifications unless other
constraints exist, including permitting or field compression limits.
(4) Aggregate wellhead natural gas volumes collected by a gathering system or
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) Straddle plant, or a plant located near a transportation pipeline that
processes gas dedicated to or gathered by a pipeline company or another
third-party.
(9) NGL production includes conversion of third-party feedstock to
iso-butane.
(10) We acquired the remaining 28% interest in Lincoln Road in December 2000.
We are currently processing all gas gathered through the Lincoln Road
gathering system at our Granger facility.
(11) MIGC is an interstate pipeline located in Wyoming and is regulated by the
Federal Energy Regulatory Commission.
(12) MGTC is a public utility located in Wyoming and is regulated by the
Wyoming Public Service Commission.
(13) Pipeline capacity represents capacity at the Powder River junction only
and does not include northern delivery points.
(14) We acquired the remaining 50% interest in Westana Gathering Company in
February 2000.
(15) A portion of the gas throughput and gas production for this gathering
system is also included in the volumes reported under Coal Bed Methane
Gathering.
(16) This facility was sold in August 2000.
(17) We contracted for the sale of this facility in December 2000. This
transaction closed in January 2001.
We expect capital expenditures related to existing operations to be
approximately $136.4 million during 2001, consisting of the following: (i)
approximately $71.8 million related to gathering, processing and pipeline
assets, of which $8.5 million is for maintaining existing facilities; (ii)
approximately $56.9 million related to exploration and production and lease
acquisition activities; and (iii) approximately $7.7 million for miscellaneous
items. Overall, capital expenditures in the Powder River basin coal bed methane
development and in southwest Wyoming operations represent 49% and 10%,
respectively, of the total 2001 budget. This budget will be increased to provide
for acquisitions if approved by our board of directors.
Gas Gathering, Processing and Transportation
Gas Gathering and Processing. We contract with producers to gather raw
natural gas from individual wells located near our plants or gathering systems.
Once we have executed a contract, we connect wells to gathering lines through
which the natural gas is delivered to a processing plant or treating facility.
At a processing plant, we compress the natural gas, extract raw NGLs and treat
the remaining dry gas to meet pipeline quality specifications. Six of our
processing plants can further separate, or fractionate, the mixed NGL stream
into ethane, propane, normal butane and natural gasoline to obtain a higher
value for the NGLs, and four of our plants are capable of processing and
treating natural gas containing hydrogen sulfide or other impurities which
require removal prior to transportation. At a treating facility, we treat dry
gas, which does not contain liquids that we can economically extract, by
removing hydrogen sulfide or carbon dioxide to meet pipeline quality
specifications.
We acquire dedicated acreage and natural gas supplies in an effort to
maintain or increase throughput levels to offset natural production declines. We
obtain these natural gas supplies by connecting additional wells, purchasing
existing systems from third parties and through internally developed projects or
joint ventures. Historically, while certain individual plants have experienced
declines in dedicated reserves, we have been successful in connecting additional
reserves to more than offset the natural declines. From 1996 through 1999, there
was a reduction in drilling activity, primarily in basins that produce oil and
casinghead gas, due to low product prices. In 2000 and continuing into 2001, gas
and oil prices increased significantly and have resulted in additional drilling
behind our systems. Overall, the level of drilling will depend upon, among other
factors, the prices for gas and oil, the drilling budgets of third-party
producers, the energy and environmental policy of the federal government and the
availability of foreign oil and gas, none of which are within our control. At
December 31, 2000,
7
our estimated dedicated reserves totaled 2.7 Tcf. In 2000, including the
reserves developed by us and associated with our partnerships and excluding the
reserves and production associated with the facilities sold during this period,
we connected new reserves to our facilities to replace approximately 222% of
throughput. In order to obtain additional dedicated acreage and to secure
contracts on favorable terms, we may participate with third-party producers in
exploration and production activities that supply our facilities. For the same
reason, we may also offer to sell ownership interests in our facilities to
selected producers.
Substantially all gas flowing through our gathering, processing and
treating facilities is supplied under three types of long-term contracts
providing for the purchase, treating or processing of natural gas for periods
ranging from five to twenty years. Approximately 69% of our plant facilities'
gross margins, or revenues at the plants less product purchases, for the month
of December 2000 resulted from percentage-of-proceeds agreements in which we are
typically responsible for the marketing of the gas and NGLs. We pay producers a
specified percentage of the net proceeds received from the sale of the gas and
the NGLs. This type of contract allows us and the producers to share
proportionally in price changes.
Approximately 17% of our plant facilities' gross margins for the month of
December 2000 resulted from contracts that are primarily fee-based from which we
receive a set fee for each Mcf of gas gathered and/or processed. This type of
contract provides us with a steady revenue stream that is not dependent on
commodity prices, except to the extent that low prices may cause a producer to
delay drilling. The proportion of fee-based contracts is expected to increase as
the volumes from the Powder River basin coal bed methane development increase.
See further discussion in "-Significant Acquisitions, Projects and
Dispositions."
Approximately 14% of our plant facilities' gross margins for the month of
December 2000 resulted from contracts that combine gathering, compression or
processing fees with "keepwhole" arrangements or wellhead purchases. Typically,
we charge producers a gathering and compression fee based upon volume. In
addition, we retain a predetermined percentage of the NGLs recovered by the
processing facility and keep 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 us to benefit when the value of the NGLs is greater as a
liquid than as a portion of the residue gas stream. However, we are adversely
affected when the value of the NGLs is lower as a liquid than as a portion of
the residue gas stream.
Transportation. We own and operate MIGC, an interstate pipeline located in
the Powder River basin in Wyoming, and MGTC, an intrastate pipeline located in
northeast Wyoming. MIGC charges a FERC approved tariff and is connected to
pipelines owned by Colorado Interstate Gas Company, Williston Basin Interstate
Pipeline Company, Kinder Morgan Interstate Pipeline Co., Wyoming Interstate
Company, Ltd. and MGTC. During 2000, MIGC operated at capacity and transported
an average of 175 MMcf/D. It is anticipated that MIGC will continue at capacity
for the next several years. See further discussion in "-Significant
Acquisitions, Projects and Dispositions," and for a further discussion of the
revenue, operating profit and attributable assets of this business segment, see
"Item 8-Financial Statements and Supplementary Data." MGTC provides
transportation and gas sales to the Wyoming cities of Gillette, Moorcroft and
Wright at rates that are subject to the approval of the Wyoming Public Service
Commission.
Significant Acquisitions, Projects and Dispositions
Our significant acquisitions, projects and dispositions since January 1,
1996 are:
Coal Bed Methane. The Powder River Basin coal bed methane area is currently
one of the largest on-shore plays for the development of natural gas in the
United States. In 2000, we were the largest producer of natural gas (together
with our partner), the largest gatherer of natural gas and the largest gas
transporter out of the basin. At December 31, 2000, we held the drilling rights
on approximately 1.1 million gross acres, or 530,000 net acres, in the basin. We
have established proven developed and undeveloped reserves totaling 350 Bcf at
December 31, 2000 on a portion of this acreage. This represents a 50% increase
in proved reserves as compared to December 31, 1999. We also estimate a net
total of 1.6 Tcf of probable reserves on an unaudited and unrisked basis
associated with undeveloped acreage in this area. There can be no assurance,
however, as to the ultimate recovery of these probable reserves. The average
drilling, completion and gathering cost for our coal bed methane gas wells is
approximately $70,000 to $90,000 with reserves per well of approximately 320
MMcf. Our average finding and development costs in this area are estimated to be
$.32 per Mcf. As deeper wells are drilled to the Big George coal, reserves per
well are expected to increase as will the average cost per well. It is expected
that the deeper Big George wells will result in a higher rate of return. Total
production from wells in which we own an interest has increased from an
8
average of approximately 128 MMcf/D at December 31, 1999 to 202 MMcf/D at
December 31, 2000. In addition to the revenues earned from the production of our
coal bed methane gas, we also earn fees for gathering and transporting the
natural gas. At December 31, 2000, we were gathering 254 MMcf per day of our own
production and of other third-party producers. Of that volume, approximately 129
MMcf per day was transported through our MIGC pipeline.
Future drilling on federal acreage will be delayed subject to completion of
the Powder River Basin Oil & Gas Environmental Impact Statement. This study is
anticipated to be completed in the second quarter of 2002. Our drilling plans
for 2001 are not expected to be substantially impacted by this study due to our
large inventory of non-federal drilling locations and our expectation that the
Bureau of Land Management, BLM, will issue drilling permits for approximately
350 well locations to prevent drainage of federal acreage. These drilling
permits will be issued when the BLM completes an Environmental Assessment, EA,
for drainage acreage. We anticipate that this EA will be issued in the second
quarter of 2001.
Additionally, the Wyoming Department of Environmental Quality, DEQ, has
revised some standards for surface water discharge that have allowed the
issuance of most of the permits that apply to the Cheyenne and Belle Fourche
drainage areas. We continue to work with both the Wyoming DEQ and Montana DEQ to
allow water discharge in the Powder River drainage area in which most of our Big
George prospects are located. The majority of wells on our acreage producing
from the Wyodak formation drain into the Cheyenne and Belle Fourche drainage
areas. We have water discharge permits in place for approximately 70 percent of
the 840 gross wells currently planned for drilling in 2001. We can make no
assurance that the conditions under which additional permits will be granted
will not impact the level of drilling or the timing of production.
Our capital budget in this area provides for expenditures of approximately
$67.2 million during 2001. This capital budget includes approximately $46.8
million for drilling costs for our interest in approximately 840 wells,
production equipment and undeveloped acreage and $20.4 million for compression.
Depending upon future drilling success, we may need to make additional capital
expenditures to continue expansion in this basin. Due to drilling and regulatory
uncertainties which are beyond our control, we can make no assurance that we
will incur this level of capital expenditure. In each of the years ended
December 31, 2000 and 1999, we expended approximately $59.1 million and $51.4
million, respectively, on this project.
In October 1997, we sold a 50% undivided interest in our Powder River basin
coal bed methane gas operations to Barrett Resources Corporation. This sale
provided us with a substantial acreage dedication for gathering and compression
services within an area of mutual interest, or AMI, additional man-power
resources to accelerate development in this area and more technical expertise
in exploration and production. The sale involved 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.
The AMI with Barrett encompasses approximately 2.1 million acres in the
Powder River basin coal bed methane development area. Both parties will continue
to develop certain specified areas within the AMI. Barrett became the operator
of the producing wells in July 1999. We have committed to gather and compress
all gas produced form the jointly-owned properties within the AMI under a
long-term fee based agreement.
In December 1998, we joined with other industry participants to form Fort
Union Gas Gathering, L.L.C., to construct a 106-mile long, 24-inch gathering
pipeline and treater to gather and treat natural gas in the Powder River basin
in northeast Wyoming. We own an approximate 13% equity interest in Fort Union
and are the construction manager and field operator. The gathering header has a
capacity of approximately 435 MMcf/D of natural gas with expansion capability
and in December 2000 it had throughput of approximately 230 MMcf/D. The header
delivers coal bed methane gas to a treating facility near Glenrock, Wyoming and
accesses interstate pipelines serving gas markets in the Rocky Mountain and
Midwest regions of the United States. The gathering header and treating system
initially went into service in September 1999 and was project financed,
requiring a cash investment by us of approximately $900,000. In conjunction with
the project financing, we also entered into a ten year agreement for firm
gathering services on 60 MMcf/D of capacity at $.14 per Mcf on Fort Union
beginning in December 1999. In the fourth quarter of 2000, we and the other
participants in the Fort Union Gas Gathering, L.L.C. approved an expansion of
the system. Construction of the 62 mile expansion has begun and will increase
the system capacity by an additional 200 MMcf/D. This project is expected to be
completed in the third quarter of 2001. This expansion, which is anticipated to
cost $25.7 million, will be project financed and will require an additional cash
investment by us of approximately $500,000. Also in connection with the
expansion, we will increase our commitment for firm gathering services by an
additional 23 MMcf/D of capacity at $.14 per Mcf.
Southwest Wyoming. Our facilities in southwest Wyoming are comprised of the
Granger and Lincoln Road facilities, or collectively the Granger Complex, and
our Red Desert facility. These facilities have a combined operational capacity
of 327 MMcf/D and processed an average of 176 MMcf/D in 2000. Our capital budget
in this area provides for expenditures of approximately $13.1 million during
2001. This capital budget includes approximately $5.8 million for drilling costs
and production equipment and approximately $7.3 million related to the gathering
systems and plant facilities. Due to drilling and regulatory uncertainties which
are beyond our control, we can make no assurance that we will incur this level
of capital expenditure. During the years ended December 31, 2000 and 1999, we
expended approximately $8.0 million and $12.4 million, respectively, on this
project. In December 2000, we acquired the remaining 28% interest in the Lincoln
Road facility for $2.6 million. This purchase price will be paid in future years
through an adjustment to the terms of the seller's gas gathering and processing
contract.
9
In 1997, we entered into an agreement with a producer to participate in
exploration and development in the Hoback basin in southwestern Wyoming. Under
the agreement, we established a 1.8 million acre AMI, in which we participate in
approximately 300,000 gross acres, or approximately 42,000 net acres.
Approximately 4,000 gross acres, or approximately 600 net acres have proven
reserves. We have also entered into agreements with the producer, or its
assigns, for the gathering and processing of natural gas, which may be developed
on 16 prospects within the AMI. Through 2000, we participated in 16 gross
development wells, or 2 net development wells, in the Jonah field of southwest
Wyoming. We also participated in 12 gross exploratory wells, or 1 net
exploratory well, in the Hoback basin. We expect to participate in the drilling
of 18 gross wells, or 2 net wells in this area during 2001. The average drilling
and completion costs per gross well are approximately $2.4 million and the
average well depth approximates 13,000 feet. Our average finding and development
costs are $.57 per Mcf. We have established proven developed and undeveloped
reserves in this area totaling 52 Bcf at December 31, 2000. This represents a
73% increase as compared to December 31, 1999. We also estimate a net total of
278 Bcf of probable reserves on an unaudited and unrisked basis associated with
undeveloped acreage in this area. There can be no assurance, however, as to the
ultimate recovery of these probable reserves.
Bethel Treating Facility. In 1996 and 1997, the Pinnacle Reef exploration
area was rapidly developing into a very active lease acquisition and exploratory
drilling area using 3-D seismic technology to identify prospects. The initial
discoveries indicated a very large potential gas development. Based on our
receipt of large acreage dedications in this area, we, through our wholly-owned
subsidiary Pinnacle Gas Treating, Inc., constructed the Bethel treating facility
for a total cost of approximately $102.8 million with a throughput capacity of
300 MMcf/D. In 1998, the production rates from the wells drilled in this field
and the recoverable reserves from these properties were far less than the
producers originally expected.
In the fourth quarter of 1998, because of uncertainties related to the pace
and success of third-party drilling programs, declines in volumes produced at
several wells and other conditions outside our control, we determined that an
evaluation of the Bethel treating facility, in accordance with accounting
standards, was necessary. We compared the net book value of the assets to the
discounted expected future cash flows of the facility and determined that the
results of this comparison required a pre-tax, non-cash impairment charge of
$77.8 million.
In December 2000, we signed an agreement with Anadarko Petroleum
Corporation for the sale of the stock of Pinnacle for approximately $38.0
million. The sale closed in January 2001 and resulted in an approximate pre-tax
gain for financial reporting purposes of $12.1 million, subject to final
accounting adjustments.
Arkoma. In August 2000, we sold our Arkoma Gathering System in Oklahoma for
gross proceeds of $10.5 million. This sale resulted in an approximate pre-tax
gain of $3.9 million.
Westana. In February 2000, we acquired the remaining 50% interest in the
Westana Gathering Company for a net purchase price of $9.8 million.
Western Gas Resources-California, Inc. In January 2000, we sold all of the
outstanding stock of our wholly-owned subsidiary, Western Gas
Resources-California, Inc., or WGR-California, for $14.9 million. The only asset
of this subsidiary was a 162 mile pipeline in the Sacramento basin of
California. The pipeline was acquired through the exercise of an option by us in
a transaction which closed simultaneously with the sale of WGR-California. We
recognized a pre-tax gain on the sale of approximately $5.4 million in the first
quarter of 2000.
Black Lake. In December 1999, we signed an agreement for the sale of our
Black Lake facility and related reserves for gross proceeds of $7.8 million,
subject to final accounting adjustment. This sale closed in January 2000. This
transaction resulted in an approximate pre-tax loss of $7.3 million which was
recognized in the fourth quarter of 1999.
MiVida. In June 1999, we sold our MiVida treating facility for gross
proceeds of $12.0 million. This transaction resulted in an approximate pre-tax
gain of $1.2 million.
Katy. In April 1999 we sold all the outstanding common stock of our wholly
owned subsidiary, Western Gas Resources Storage, Inc., for gross proceeds of
$100.0 million. This transaction resulted in an approximate pre-tax loss of
$17.7 million, in 1999. The only asset of this subsidiary was the Katy facility.
We also sold 5.1 Bcf of stored gas in the Katy facility for total sales proceeds
of $11.7 million, which approximated our cost of the inventory. To meet the
needs of our marketing operations, we continue to contract for storage capacity
at the Katy facility and in other locations. At the time of the sale, we entered
into a long-term agreement with the purchaser for approximately 3 Bcf of storage
capacity at market rates through March 2002.
10
a AGE>
Giddings. In April 1999, we sold our Giddings facility for gross proceeds
of $36.0 million, which resulted in an approximate pre-tax loss of $6.6 million
in the second quarter of 1999.
Edgewood. In two transactions which closed in October 1998 we sold our
Edgewood gathering system, including our undivided interest in the producing
properties associated with this facility, and our 50% interest in the Redman
Smackover Joint Venture. The combined sales price was $55.8 million. We
recognized a pre-tax gain of approximately $1.6 million during the fourth
quarter of 1998.
Perkins. In November 1997, we entered into an agreement to sell our Perkins
facility. In March 1998, we completed the sale of this facility, with an
effective date of January 1, 1998. The sales price was $22.0 million and
resulted in a pre-tax gain of approximately $14.9 million.
Other. We routinely review the economic performance of each of our
operating facilities to ensure that a targeted rate of return is achieved. If an
operating facility is not generating targeted returns we will explore various
options, such as consolidation with other Western-owned or third-party-owned
facilities, dismantlement, asset swap or sale.
Producing Properties
We selectively participate in exploration and production activities largely
to secure additional gas supply for our facilities. Beginning in 1997, we
substantially increased our investment in the acquisition of undeveloped acreage
and development of the Powder River Basin coal bed methane and during 2000 we
invested $44.1 million in this project. This play has now developed into one of
our most significant long-term holdings. We also have production and undeveloped
acreage in the Jonah and Hoback basins of southwest Wyoming and the Sand Wash
basin in northwest Colorado. See "--Significant Acquisitions, Projects and
Dispositions--Coal Bed Methane" and "--Southwest Wyoming." We will also consider
investing in other exploration and production prospects in the Rocky Mountains
and in Canada that we believe to be low risk and that could lead to
opportunities for our gathering and processing or marketing businesses.
Revenues derived from our producing properties comprised approximately
2.7%, 1.6% and 1.3% of consolidated revenues for the years ended December 31,
2000, 1999 and 1998, respectively. The operating margin (revenues less product
purchases and operating expenses) derived from our producing properties
comprised approximately 26.5%, 15.4% and 11.4% of consolidated gross margin for
the years ended December 31, 2000, 1999 and 1998, respectively. As a result of
the increased investment in the Powder River coal bed methane, we expect both
the revenues and operating margin derived from our producing properties to
continue to increase.
The following table provides a summary of our net annual production
volumes:
December 31,
---------------------------------------------------------------------------
2000 1999 1998
------------------------ ----------------------- -----------------------
Gas Oil Gas Oil Gas Oil
State/Basin (MMcf) (MBbl) (MMcf) (MBbl) (MMcf) (MBbl)
- ------------------------------------------ ----------- ----------- ----------- --------- ----------- --------
Colorado............................... 387 2 332 3 274 2
Louisiana (1) ......................... - - 2,270 64 2,810 70
Texas (1).............................. 36 3 62 4 1,008 5
Wyoming:
Coal Bed Methane.................... 25,552 - 12,766 - 7,136 -
All Other........................... 2,044 23 2,558 41 3,283 40
----------- ----------- ----------- --------- ----------- --------
Total.................................... 28,019 28 17,988 112 14,511 117
=========== =========== =========== ========= =========== ========
(1) We sold our producing properties in Louisiana during 1999 and the majority
of our producing properties in Texas during 1998.
11
PAGE>
The following table provides a summary of our proved developed and proved
undeveloped net reserves:
December 31,
---------------------------------------------------------------------------
2000 1999 1998
------------------------ ---------------------- -----------------------
Gas Oil Gas Oil Gas Oil
State/Basin (MMcf) (MBbl) (MMcf) (MBbl) (MMcf) (MBbl)
- ------------------------------------------ ----------- ----------- ----------- --------- ----------- --------
Colorado............................... 6,658 30 6,452 40 2,278 8
Louisiana (1).......................... - - - - 10,234 190
Texas (1).............................. - - - - - -
Wyoming:
Coal Bed Methane.................... 350,512 - 236,277 - 193,010 -
All Other........................... 51,324 409 29,089 289 33,408 359
----------- ---------- ---------- --------- ----------- --------
Total.................................... 408,494 439 271,818 329 238,930 557
=========== ========== ========== ========= =========== ========
(1) We sold our producing properties in Louisiana during 1999 and the majority
of our producing properties in Texas during 1998.
We employ a total staff of six full time reservoir and production engineers
and geologists who complete annual reserve estimates of dedicated reserves
behind each of our existing facilities. The reserve report for the Powder River
coal bed methane gas and other Wyoming assets for 2000 has been audited by
Netherland, Sewell & Associates, Inc.
The estimates of probable reserves to our interest associated with the
Powder River basin coal bed area and our undeveloped acreage in southwest
Wyoming are unaudited and unrisked. The estimate of probable reserves for the
Powder River basin coal bed methane development was calculated by estimating the
total recoverable gas in place on our acreage position. This estimate was based
on both the primary and secondary coal objectives. The thickness for each coal
at each location was derived from internal and published geological information.
The estimate of the gas contained in the primary and secondary coals was based
on the storativity isotherm as calculated from proprietary core samples obtained
across our acreage holding using an 85% recovery factor. The probable reserves
were determined by deducting the proved reserves as audited by Netherland,
Sewell, and Associates, Inc. from the estimated total recoverable gas in place.
The probable reserves for the southwest Wyoming area were estimated from
geologic interpretations of the undeveloped area and analogies to producing
wells in the same areas.
Our reserve estimates are subject to numerous uncertainties inherent in the
estimation of quantities of proved and probable reserves, the projection of
future rates of production and the timing of development expenditures. The
accuracy of these estimates is a function of the quality of available data and
of engineering and geological interpretation and judgment. Reserve estimates are
imprecise and should be expected to change as additional information becomes
available. 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. In addition, the estimates of future net revenues from
our proved reserves and the present value of those reserves are based upon
certain assumptions about production levels, prices and costs, which may not be
correct. Further, the volumes considered to be commercially recoverable
fluctuate with changes in prices and operating costs. The meaningfulness of such
estimates is highly dependent upon the accuracy of the assumptions upon which
they were based. Actual results may differ materially from the results
estimated. Our estimates of reserves dedicated to our gathering and processing
facilities are calculated by our reservoir engineering staff and are based on
publicly available data. These estimates may be less reliable than the reserve
estimates made for our own producing properties since the data available for
estimates of our own producing properties also includes our proprietary data.
Marketing
Gas. We market gas produced at our plants and purchased from third parties
to end-users, local distribution companies, or LDCs, pipelines and other
marketing companies throughout the United States and Canada. Historically, our
gas marketing was an outgrowth of our gas processing activities and was directed
towards selling gas processed at our plants to ensure their efficient operation.
As we expanded into new basins and the natural gas industry became deregulated
and offered more opportunity, we began to increase our third-party gas
marketing. For the year ended December 31, 2000, our gas sales volumes averaged
1.8 Bcf/D. Third-party sales and our gas storage positions, combined with the
stable supply of gas from our facilities and production, enable us to respond
quickly to changing market conditions and to take advantage of seasonal price
variations and peak demand periods. We sell gas under agreements with varying
terms and conditions in order to match seasonal and other changes in demand. The
duration of our sales contracts range from one day to nine years. In addition to
our offices in Denver and Houston, we have a marketing office in Calgary,
Alberta. The Calgary office also provides us with information regarding market
conditions in Canada which affects the gas markets in the United States.
Our 2001 gas marketing plan emphasizes growth through our asset base and
storage and transportation capacities which we control. In general, we do not
expect to increase our third-party sales volumes in 2001 significantly from
levels achieved in 2000. With natural gas prices at historically high levels, we
continually monitor and
12
review the credit exposure to our marketing counter parties. This review has
resulted in a temporary reduction in sales volumes with various counter parties
in order to maintain acceptable credit exposures. During 2000, we reserved
approximately $1.6 million for doubtful accounts. During the year ended December
31, 2000, we sold gas to approximately 301 end-users, pipelines, LDCs and other
customers. One customer accounted for approximately 6% of our consolidated
revenues from the sale of gas, or 5% of total consolidated revenue, for the year
ended December 31, 2000. This customer is a large integrated utility.
We continue to view access to storage capacity and firm transportation as
significant elements of our marketing strategy. We customarily store gas in
underground storage facilities to ensure an adequate supply for long-term sales
contracts and for resale during periods when prices are favorable. As of
December 31, 2000, we had contracts in place for approximately 12.1Bcf of
storage capacity. The fees associated with these contracts at December 31, 2001
do not exceed $.61 per Mcf and the associated contract periods range from two
months to five years. As of December 31, 2000, we also had contracts for
approximately 587 MMcf/D of firm transportation. The fees associated with these
contracts do not exceed $.50 per Mcf, and the associated contract periods range
from three months to eight years. Several of these long-term storage and firm
transportation contracts require an annual renewal. In addition, some contracts
contain provisions requiring us to pay the fees associated with these contracts
whether or not the service is used. We have also entered into 158 MMcf/D of firm
transportation precedent agreements for transportation on pipeline expansions
which are not completed. These expansions are anticipated to be completed in
2001 and 2002. When the expansions are completed, we will enter into firm
transportation agreements.
We held gas in storage and in imbalances at various facilities of
approximately 10.9 Bcf at an average cost of $3.88 per Mcf at December 31, 2000
compared to 13.7 Bcf at an average cost of $2.40 per Mcf at December 31, 1999.
At December 31, 2000, we had hedging contracts in place for anticipated sales of
approximately 10.7 Bcf of stored gas at a weighted average price of $4.69 per
Mcf for the stored inventory. See further discussion in "--Significant
Acquisitions, Projects and Dispositions--Katy" and "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Liquidity and Capital
Resources--Risk Management Activities."
NGLs. We market NGLs, or ethane, propane, iso-butane, normal butane,
natural gasoline and condensate, produced at our plants and purchased from third
parties, in the Rocky Mountain, Mid-Continent, Gulf Coast and Southwestern
regions of the United States. A majority of our 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, we seek to
ensure that products from our plants move on a reliable basis, avoiding
curtailment of production. For the year ended December 31, 2000, NGL sales
averaged 3,085 MGal/D.
Consumers of NGLs are primarily 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, consumers use propane for home
heating, transportation and for agricultural applications. Price, seasonality
and the economy primarily affect the demand for NGLs.
We increased sales to third parties by approximately 200 MGal/D for the
year ended December 31, 2000 compared to 1999. In general, we do not anticipate
that sales to third parties in 2001 will vary significantly from those
experienced in 2000. Our NGL marketing plan contemplates: (i) continued growth
in sales to end-users without increasing total sales volume; (ii) maximizing
profitability on volumes produced at our facilities; and (iii) efficient use of
various third-party storage facilities to increase profitability while limiting
carrying risk.
From time to time, we lease NGL storage space at major trading locations in
order to store products for resale during periods when prices are favorable and
to facilitate the distribution of products. As of December 31, 2000, we had no
contracts in place requiring the payment of any base fee. We held NGLs in
storage under exchange agreements of 6,229 MGal, consisting primarily of propane
and normal butane, at an average cost of $.49 per gallon and 8,600 MGal, at an
average cost of $.34 per gallon at December 31, 2000 and 1999, respectively. At
December 31, 2000, we had no significant hedging contracts in place for these
volumes.
During the year ended December 31, 2000, we sold NGLs to 138 customers.
These customers are end-users, fractionators, chemical companies and other
customers. Three customers accounted for approximately 35% of our consolidated
revenues from the sale of NGLs, or 6% of total consolidated revenue, for the
year ended December 31, 2000.
13
These customers are all large integrated energy companies. We also derive
revenues from contractual marketing fees charged to some producers for NGL
marketing services. For the year ended December 31, 2000, these fees were less
than 1% of our consolidated revenues.
Environmental
The construction and operation of our gathering systems, plants and other
facilities used for the gathering, processing, treating or transportation 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 our facilities or at facilities to which we send wastes for
disposal. In most instances, the applicable regulatory requirements relate to
water and air pollution control or waste management. We employ four
environmental engineers, four safety specialists and three regulatory compliance
specialists to monitor environmental and safety compliance at our facilities.
Prior to consummating any major acquisition, our environmental engineers perform
audits on the facilities to be acquired. In addition, on an ongoing basis, the
environmental engineers perform environmental assessments of our existing
facilities. We believe that we are in substantial compliance with applicable
material environmental laws and regulations. Environmental regulation can
increase the cost of planning, designing, constructing and operating our
facilities. We believe that the costs for compliance with current environmental
laws and regulations have not had and will not have a material effect on our
financial position or results of operations.
The Texas Natural Resource Conservation Commission, which has authority to
regulate, among other things, stationary air emissions sources, has created a
committee to make recommendations to the Commission regarding a voluntary
emissions reduction plan for the permitting of existing "grand-fathered" air
emissions sources within Texas. A "grand-fathered" air emissions source is one
that does not need a state operating permit because it was constructed prior to
1971. We operate a number of these sources within Texas, including portions of
our Midkiff/Benedum, Gomez and Mitchell Puckett systems. In connection with a
modernization program, we are replacing all of our "grand-fathered" compressors
in Texas and expect to complete this process in 2001. Other "grand-fathered"
sources, if not permitted or modified, may be subject to increasing emissions
fees beginning in 2002. We do not believe that such increases will have a
material effect on our financial position or results of operations.
We anticipate that it is reasonably likely that the trend in environmental
legislation and regulation will continue to be towards stricter standards. We
are unaware of future environmental standards that are reasonably likely to be
adopted that will have a material effect on our financial position or results of
operations, but we cannot rule out that possibility.
We are in the process of voluntarily cleaning up substances at certain
facilities that we operate. Our expenditures for environmental evaluation and
remediation at existing facilities have not been significant in relation to our
results of operations and totaled approximately $2.4 million for the year ended
December 31, 2000, including approximately $417,000 in air emissions fees to the
states in which we operate. Although we anticipate that such environmental
expenses per facility will increase over time, we do not believe that such
increases will have a material effect on our financial position or results of
operations.
Competition
We compete with other companies in the gathering, processing, treating and
marketing businesses both for supplies of natural gas and for customers for our
natural gas and NGLs, and for the acquisition of leaseholds. Competition for
natural gas supplies is primarily based on the efficiency and reliability of our
services, the availability of transportation and the ability to obtain a
satisfactory price for natural gas and NGLs. Our competitors for obtaining
additional gas supplies, for gathering and processing gas and for marketing gas
and NGLs include national and local gas gatherers, brokers, marketers and
distributors of various sizes and experience. The majority of these competitors
have much larger financial resources than us. For customers that have the
capability of using alternative fuels, such as oil and coal, we also compete for
their business based on the price and availability of such alternative fuels.
Our competitors for obtaining leaseholds include major and large independent oil
companies as well as smaller independent oil companies and brokers. Competition
for sales customers is primarily based upon reliability and price of deliverable
natural gas and NGLs. In recent years, we have experienced narrowing margins
related to third-party sales due to the increasing availability of pricing
information in the natural gas industry. Suppliers in our gas marketing
transactions may request additional security such as letters of credit that are
not required of some of our competitors.
14
Regulation
Our purchase and sale of natural gas and the fees we receive for gathering
and processing have generally not been subject to regulation, however, some
aspects of our business are subject to federal, state and local laws and
regulations which can have a significant impact upon our overall operations.
As a processor and marketer of natural gas, we depend on the transportation
and storage services offered by various interstate and intrastate pipeline
companies for the delivery and sale of our own gas supplies as well as those we
process and/or market for others. Both the interstate pipelines' performance of
transportation and storage services, and the rates charged for such services,
are subject to the jurisdiction of the Federal Energy Regulatory Commission,
FERC, under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978.
At times, other system users can pre-empt the availability of interstate
transportation and storage services necessary to enable us to make deliveries
and/or sales of gas in accordance with FERC-approved methods for allocating the
system capacity of open access pipelines. Moreover, the rates the pipelines
charge 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
our processing and marketing operations and/or adversely affect our sales
margins.
Generally, neither the FERC nor any state agency regulates gathering and
processing prices. The Oklahoma Corporation Commission, or the OCC, has 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 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 which a gas gatherer provides. In addition, the state
legislatures and regulators in other states in which we gather gas are also
contemplating additional regulation of gas gathering. We do not believe that any
of the proposed legislation of which we are aware is likely to have a material
adverse effect on our financial position or results of operation. However, we
cannot predict what additional legislation or regulations the states may adopt
regarding gas gathering.
The construction of additional gathering and processing facilities and the
development of natural gas reserves require permits from several federal, state
and local agencies. In the past we have been successful in receiving all permits
necessary to conduct our operations. There can be no assurance, however, that
permits in the future will be obtainable or issued timely or that the terms of
any permits will be compatible with our business plans.
Employees
At December 31, 2000, we employed approximately 616 full-time employees,
none of whom was a union member. We consider relations with employees to be
excellent.
ITEM 3. LEGAL PROCEEDINGS
Reference is made to Note 8 of our 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, 2000.
15
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
As of March 1, 2001, there were 32,410,922 shares of Common Stock
outstanding held by 235 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
------ ------
2000
Fourth Quarter................................. $ 34 3/4 $ 21 7/8
Third Quarter.................................. 27 1/4 18 1/8
Second Quarter................................. 23 1/2 15 1/2
First Quarter.................................. 17 7/8 10 7/8
1999
Fourth Quarter................................. $ 18 3/4 $ 10 7/8
Third Quarter.................................. 19 3/4 15 1/8
Second Quarter................................. 17 7/8 7 1/2
First Quarter.................................. 7 5/8 3 7/8
We paid annual dividends on our Common Stock aggregating $.20 per share
during the years ended December 31, 2000 and 1999. We have declared a dividend
of $.05 per share of Common Stock for the quarter ending March 31, 2001 to
holders of record as of March 31, 2001. Declarations of dividends on our Common
Stock are within the discretion of the Board of Directors. In addition, our
ability to pay dividends on our Common Stock is restricted by certain covenants
in our financing facilities, the most restrictive of which prohibits declaring
or paying dividends that exceed, in the aggregate the sum of $20 million plus
50% of our consolidated net operating income (as defined in the subordinated
note indenture) earned after July 1, 1999 (or minus 100% if a net loss) plus the
aggregate net cash proceeds received after July 1, 1999 from the sale of any
stock. At December 31, 2000, availability under this covenant was approximately
$25.7 million.
16
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected consolidated historical financial
and operating data for Western. Certain prior year amounts have been
reclassified to conform to the presentation used in 2000. The data for the three
years ended December 31, 2000, 1999 and 1998 should be read in conjunction with
our Consolidated Financial Statements and the notes thereto included elsewhere
in this Form 10-K. The selected consolidated financial data for the years ended
December 31, 1997 and 1996 is derived from our audited historical Consolidated
Financial Statements. See also Item 7 - "Management's Discussion and Analysis of
Financial Condition and Results of Operations."
Year Ended December 31,
--------------------------------------------------------------------------------
2000 1999 1998 1997 1996
------------- ------------ ------------ ------------ -----------
(000s, except per share amounts and operating data)
Statement of Operations:
Revenues ................................. $ 3,281,988 $1,910,724 $ 2,117,088 $ 2,380,545 $ 2,088,262
Gross profit (a) .......................... 158,561 37,487 66,568 93,755 105,479
Income (loss) before income taxes ......... 91,384 (25,184) (b) (105,623) (b) 2,220(b) 41,631
Provision (benefit) for income taxes ...... 33,562 (9,167) (38,418) 733 13,690
Income (loss) before extraordinary items .. 57,822 (16,017) (b) (67,205) (b) 1,487(b) 27,941
Extraordinary charge for early extinguish-
ment of debt .......................... (1,714) (c) (1,107) (c) - - -
Net income (loss) ......................... 56,108 (17,124) (b) (67,205) (b) 1,487(b) 27,941
Earnings (loss) per share of
common stock ........................... 1.42 (.86) (2.42) (.28) .66
Earnings (loss) per share of
common stock - assuming dilution ....... 1.39 (.86) (2.42) (.28) .66
Other financial data:
Net cash provided by operating
activities ............................. 116,262 95,184 (35,570) 114,755 168,266
EBITDA, as adjusted(d) .................... 173,357 92,413 79,291 118,404 137,233
Capital expenditures ...................... 108,536 81,489 105,216 198,901 74,555
Balance Sheet Data
(at year end):
Total assets .............................. 1,431,422 1,049,486 1,219,377 1,348,276 1,361,631
Long-term debt ............................ 358,700 378,250 504,881 441,357 379,500
Stockholders' equity ...................... 391,534 349,743 385,216 468,112 480,467
Dividends on preferred stock .............. 10,416 10,439 10,439 10,439 10,439
Dividends on common stock ................. 6,448 6,426 6,430 6,427 5,472
Operating Data:
Average gas sales (MMcf/D) ................ 1,835 1,900 2,200 1,975 1,794
Average NGL sales (MGal/D) ................ 3,085 2,885 4,730 4,585 3,744
Average gas volumes
gathered (MMcf/D) ...................... 1,521 1,214 1,162 1,229 1,171
Facility capacity (MMcf/D) ................ 2,374 2,485 2,237 2,302 1,940
Average gas prices ($/Mcf) ................ $ 3.90 $ 2.17 $ 2.01 $ 2.30 $ 2.19
Average NGL prices ($/Gal) ................ $ .52 $ .33 $ .26 $ .36 $ .41
17
(a) Excludes selling and administrative, interest, restructuring and income
tax expenses, expenses for the impairment of property and equipment and
any extraordinary items. See further discussion in notes (b), (c) and
(d).
(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," or SFAS No. 121, requires that an impairment loss be recognized when
the carrying amount of an asset exceeds its fair market value or the
expected future undiscounted net cash flows. In accordance with SFAS No.
121, we recognized a pre-tax, non-cash loss on the impairment of property
and equipment of $1.2 million, or $0.7 million after-tax, $108.5 million,
or $69.0 million after-tax, and $34.6 million or $22.0 million after-tax
for the years ended December 31, 1999, 1998 and 1997, respectively.
(c) We recognized an after-tax extraordinary charge on the early
extinguishment of long-term debt in 2000 and in 1999 of $1.7 million and
$1.1 million, respectively.
(d) Reflects income before interest expense, income taxes, depreciation,
depletion and amortization, $1.2 million, $108.5 million and $34.6
million of non-cash impairment losses related to certain oil and gas
assets and plant facilities in each of 1999, 1998 and 1997, respectively,
in connection with SFAS No. 121, (gains) or losses on sales of assets of
$(9.4) million, $29.8 million, $16.5 million, $4.7 million and $2.0
million in each of 2000, 1999, 1998, 1997 and 1996, respectively and $1.7
million and $1.1 million of after-tax charges on the early extinguishment
of long-term debt in each of 2000 and 1999, respectively. This data does
not purport to reflect any measure of operations or cash flow. EBITDA is
not a measure determined pursuant to generally accepted accounting
principles, or GAAP, nor is it an alternative to GAAP income.
18
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
our consolidated financial condition and results of operations for the three
years ended December 31, 2000, 1999 and 1998. Certain prior year amounts have
been reclassified to conform to the presentation used in 2000. Reference should
also be made to our 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, 2000 compared to year ended December 31, 1999
(000s, except per share amounts and operating data)
Year Ended
December 31,
---------------------------- Percent
2000 1999 Change
------------ ------------- ------
Financial results:
Revenues............................................................... $ 3,281,988 $ 1,910,724 72
Gross profit........................................................... 158,561 37,487 298
Net income (loss)...................................................... 56,108 (17,124) -
Income (loss) per share of common stock ............................... 1.42 (.86) -
Income (loss) per share of common stock - assuming dilution............ 1.39 (.86) -
Net cash provided by operating activities.............................. $ 116,262 $ 95,184 22
Operating data:
Average gas sales (MMcf/D)............................................. 1,835 1,900 (3)
Average NGL sales (MGal/D)............................................. 3,085 2,885 7
Average gas prices ($/Mcf)............................................. $ 3.90 $ 2.17 80
Average NGL prices ($/Gal)............................................. $ .52 $ .33 58
Net income increased $73.2 million for the year ended December 31, 2000
compared to 1999. The increase in net income was primarily attributable to
significantly higher gas and NGL prices in 2000 compared to the prior year,
increased production from the Powder River coal bed methane development,
improved marketing margins, an after-tax gain of $3.3 million recognized on the
sale of the stock of our wholly-owned subsidiary, Western Gas
Resources-California, in the first quarter of 2000 and an after-tax gain of $2.4
million recognized on the sale of the Arkoma gathering system in the third
quarter of 2000. These increases were partially offset by after-tax losses on
hedging activities on our equity gas and NGLs of $24.6 million and an after-tax
extraordinary charge of $1.7 million for the early extinguishment of long-term
debt also in the third quarter of 2000. The results for the year ended December
31, 1999 were negatively impacted by a combined after-tax loss of $21.6 million
from the sale of the Giddings, Katy, MiVida and Black Lake facilities and
related severance charges, settlement of ongoing litigation and an after-tax
extraordinary charge of $1.1 million for the early extinguishment of long-term
debt.
Revenues from the sale of gas increased $1,123.3 million to $2,624.4
million for the year ended December 31, 2000 compared to 1999. This increase was
due to an improvement in product prices in 2000 which more than offset a
reduction in sales volume. Average gas prices realized by us increased $1.73 per
Mcf to $3.90 per Mcf for the year ended December 31, 2000 compared to 1999.
Average gas sales volumes decreased 65 MMcf per day to 1,835 MMcf per day for
the year ended December 31, 2000 compared to 1999. This decrease was due to a
reduction in the sale of gas purchased from third parties resulting from the
sale in 1999 of our Katy gas storage facility which more than offset an increase
in volumes available from our coal bed methane production.
Revenues from the sale of NGLs increased approximately $244.1 million for
the year ended December 31, 2000 compared to 1999. This increase is due to an
improvement in product prices and an increase in sales volume. Average NGL
prices realized by us increased $.19 per gallon to $.52 per gallon for the year
ended December 31, 2000 compared to 1999. Average NGL sales volumes increased
200 MGal per day to 3,085 MGal per day for the year ended December 31, 2000
compared to 1999. This increase in NGL volume is due to an increase in the sale
of NGLs purchased from third parties.
19
Product purchases increased by $1,269.7 million for the year ended December
31, 2000 compared to 1999 primarily due to an increase in commodity prices and
an increase in NGLs purchased from third parties. Overall, combined product
purchases as a percentage of sales of all products remained constant at 93% for
the year ended December 31, 2000 and in 1999.
Marketing margins on residue gas averaged $.017 per Mcf in 2000. This
represents a significant increase as compared to the margin realized during 1999
of $.011 per Mcf. The margins realized in 2000 are reflective of the current
volatile market conditions and our ability to benefit from these conditions
through our transportation arrangements. Marketing margins on NGLs averaged
$.007 per gallon for the year ended December 31, 2000 compared to approximately
$.004 per gallon in 1999. There is no assurance, however, that these market
conditions for our gas and NGL products and related margins will continue in the
future or that we will be in a similar position to benefit from them. In
addition, during 2000, we reserved a total of $1.6 million for doubtful
accounts. This reserve is not included in the calculation of the marketing
margins and is reported in Selling and administrative expenses.
Oil and gas exploration and production expenses increased $10.3 million for
the year ended December 31, 2000 compared to 1999. These increases are due to
increased production taxes and lease operating expenses resulting from our
increased drilling and production activities in the Powder River coal bed
methane development.
Selling and administrative expenses increased $5.4 million for the year
ended December 31, 2000 compared to 1999. These increases are due to higher
insurance costs, increased compensation and severance costs, increased accruals
for doubtful accounts and compensation recorded for re-priced stock options.
Depreciation, depletion and amortization increased by $6.9 million for the
year ended December 31, 2000 compared to 1999 primarily as a result of our
increasing operations in the Powder River basin coal bed methane development and
our acquisition of the remaining 50% of the Westana Gathering Company in the
first quarter of 2000. These increases more than offset reductions in
depreciation from the sales of our Giddings, Katy, MiVida and Black Lake
facilities in 1999.
In 2000, we realized a net pre-tax gain of $9.4 million on the sale of our
California subsidiary and our Arkoma gathering system. In 1999, we realized a
net pre-tax loss of $29.8 million on the sales of our Giddings, Katy, MiVida and
Black Lake facilities.
Extraordinary charge for early extinguishment of debt increased by a net
after-tax charge of $600,000 for the year ended December 31, 2000 compared to
1999. In 2000, we prepaid $27.0 million of outstanding indebtedness to insurance
companies, originally due to be paid in November 2005, with funds available
under our Revolving Credit Facility. In connection with this prepayment, we
incurred approximately $2.8 million for pre-tax yield maintenance and other
charges. This compares to the prepayment in 1999 of $84.0 million of
indebtedness to various insurance companies. In connection with the 1999
prepayments, we incurred approximately $1.8 million for pre-tax yield
maintenance and other charges.
Year ended December 31, 1999 compared to year ended December 31, 1998
(000s, except per share amounts and operating data)
Year Ended
December 31,
---------------------------- Percent
1999 1998 Change
-------------- ------------ ------
Financial results:
Revenues............................................................... $ 1,910,724 $ 2,117,088 (10)
Gross profit........................................................... 37,487 66,568 (44)
Net loss............................................................... (17,124) (67,205) 75
Loss per share of common stock ........................................ (.86) (2.42) 64
Loss per share of common stock - assuming dilution..................... (.86) (2.42) 64
Net cash provided by (used in) operating activities.................... $ 95,184 $ (35,570) -
Operating data:
Average gas sales (MMcf/D)............................................. 1,900 2,200 (14)
Average NGL sales (MGal/D)............................................. 2,885 4,730 (39)
Average gas prices ($/Mcf)............................................. $ 2.17 $ 2.01 8
Average NGL prices ($/Gal)............................................. $ .33 $ .26 27
20
Overall, the net loss decreased $50.1 million for the year ended December
31, 1999 compared to 1998. The decrease in net loss for the year was primarily
due to a 1998 $69.0 million, after-tax, charge for impairment recorded in 1998
in connection with the evaluation of a decrease in product prices and the impact
on our Bethel, Black Lake and Sand Dunes facilities, as required by SFAS No.
121.
Revenues from the sale of gas decreased approximately $110.5 million for the
year ended December 31, 1999 compared to 1998. Average gas sales volumes
decreased 300 MMcf per day to 1,900 MMcf per day for the year ended December 31,
1999 compared to 1998, primarily due to an decrease in third-party sales
activity. The decrease in volumes sold was partially offset by an increase in
average gas prices. Our average gas price increased $.16 per Mcf to $2.17 per
Mcf for the year ended December 31, 1999 compared to 1998. Included in this gas
price is approximately $4.1 million of loss recognized in the year ended
December 31, 1999 related to futures positions on equity volumes.
Revenues from the sale of NGLs decreased approximately $102.9 million for
the year ended December 31, 1999 compared to 1998. Average NGL sales volumes
decreased 1,845 MGal per day to 2,885 MGal per day for the year ended December
31, 1999 compared to 1998, due to a decrease in third-party sales activity of
1,325 MGal per day and a decrease in plant sales volumes of 520 MGal per day.
Plant NGL sales volumes were largely affected by increased volumes taken in kind
and curtailed drilling activity due to low oil prices by a producer behind
Midkiff, and the sale of our Edgewood and Giddings facilities. Volumes taken in
kind affect sales volumes and revenues but do not materially affect income. The
decrease in sales volumes was partially offset by an increase in average NGL
prices. Our average NGL price increased $.07 per gallon to $.33 per gallon for
the year ended December 31, 1999 compared to 1998. Included in this NGL price
was approximately $6.6 million of loss recognized in the year ended December 31,
1999 related to futures positions on equity volumes.
Processing, transportation and storage revenue increased approximately $4.3
million for the year ended December 31,1999 compared to 1998 due to increased
volumes transported by our MIGC pipeline resulting from the activity in the
Powder River basin.
The reduction in product purchases of $198.5 million to $1.7 billion for the
year ended December 31, 1999 compared to 1998, was primarily due to a decrease
in product prices. Overall, combined product purchases as a percentage of sales
of all products remained constant at 93% for the year ended December 31, 1999
compared to 1998. Our margins on third-party sales of natural gas have narrowed
from $.03 per Mcf in 1997 to $.01 per Mcf in 1999. This decrease is partially
due to increasing competitiveness in the marketplace. Contributing to this
decrease in 1999 was the sale of our Katy storage facility in April 1999. This
facility generated higher margins per Mcf as we were able to capture the
summer/winter price differential on our storage position.
Plant operating expense decreased approximately $17.9 million for the year
ended December 31, 1999 compared to 1998. The decrease was primarily due to the
reorganization of our operating areas as a result of the sales of the Giddings,
MiVida, and Katy facilities during 1999.
Depreciation, depletion and amortization decreased approximately $8.4
million for the year ended December 31, 1999 compared to 1998. The decrease was
primarily due to the sales of the Giddings, MiVida, and Katy facilities during
1999 and impairment charges recognized against our Bethel and Black Lake
facilities in 1998 and 1997.
Interest expense decreased $500,000 for the year ended December 31, 1999
compared to 1998. The decrease is the result of an overall reduction in long-
term debt of $126.6 million with the proceeds from our asset sales in 1999. The
resulting decrease in interest expense was partially offset by higher interest
rates on our Senior Debt facilities and on the Senior Subordinated Debt. In
connection with the repayments on the Senior Debt, we incurred approximately
$1.8 million of pre-tax yield maintenance and other charges. These charges are
reflected as an extraordinary charge from early extinguishment of long-term debt
in 1999.
Business Strategy
In 1998 and 1999, as oil and gas prices were approaching historical lows,
our activities were focused on consolidating our businesses in our core
operating regions and reducing our outstanding debt. Improved product prices
throughout 2000 and continuing into 2001 along with our improved financial
position will allow us to emphasize the growth aspects of our business strategy.
Our long-term business plan is to increase our profitability by: (i) optimizing
the efficiency and utilization of our existing operations; (ii) developing
natural gas reserves and increasing production volumes on our existing acreage
positions;
21
and (iii) investing in projects or acquiring assets that complement and extend
our core natural gas gathering, processing, production and marketing businesses.
With our improved financial position, in 2001, we will actively evaluate
acquisitions of either assets or companies. These acquisitions can be related to
gathering and processing or production with emphasis on properties located in
the Rocky Mountains or Canada. Capital expenditures budgeted for existing
operations in 2001 are estimated to be approximately $136.4 million. This
includes approximately $71.8 million related to gathering, processing and
pipeline assets and approximately $53.4 million for the acquisition of
undeveloped acreage and development of gas reserves in the Powder River basin.
This budget will be increased to provide for acquisitions if approved by our
board of directors.
We constantly seek to improve the profitability of our existing operations
by increasing natural gas throughput levels through new well connections and
expansion of our gathering systems, increasing our efficiency through the
modernization of equipment and consolidation of existing gathering and
processing facilities, evaluating the economic performance of each of our
operating facilities to ensure that a targeted rate of return is achieved and
controlling operating and overhead expenses.
We continually seek to increase reserves dedicated to our facilities. Our
operations are located in some of the most actively drilled oil and gas
producing basins in the United States. We enter into agreements under which we
gather and process natural gas produced on acreage dedicated to us by third
parties. We contract for production from new wells and newly dedicated acreage
in order to replace declines in existing reserves or increase reserves that are
dedicated for gathering and processing at our facilities. At December 31, 2000,
our estimated dedicated reserves totaled 2.7 Tcf. In 2000, including the
reserves developed by us and associated with our partnerships and excluding the
reserves and production associated with the facilities sold during this period,
we connected new reserves to our facilities to replace approximately 222% of
throughput. In order to obtain additional dedicated acreage and to secure
contracts on favorable terms, we may participate to a limited extent with third-
party producers in exploration and production activities that supply our
facilities. For the same reason, we may also offer to sell ownership interests
in our facilities to selected producers.
We selectively participate in exploration and production activities largely
to secure additional gas supply for our facilities. Beginning in 1997, we
substantially increased our investment in the acquisition of undeveloped acreage
and development of the Powder River coal bed methane. We have acquired drilling
rights on approximately 530,000 net acres in the basin. At December 31, 2000 we
have proved developed and undeveloped reserves of approximately 350 Bcf on a
portion of this acreage. We also have participated in the development of
properties in southwest Wyoming and Colorado. These properties have an
additional 58Bcf of proved developed and undeveloped reserves. This represents
an increase of approximately 50% in our proved reserves from December 31, 1999.
We also estimate a net total of 1.9 Tcf of probable or possible reserves on an
unrisked basis associated with undeveloped acreage in these areas. There can be
no assurance, however, as to the ultimate recovery of these probable or possible
reserves. We will also consider investing in other exploration and production
prospects that we consider to be low risk and complementary to our other
business segments.
We will continue to invest in projects that complement and extend our core
natural gas gathering, processing, production and marketing businesses including
the consideration of expansion into additional geographic areas in the
continental United States and Canada.
In the third quarter of 2000, our board of directors retained an executive
search firm to identify and evaluate both internal and external candidates to
replace our current Chief Executive Officer and President, Lanny Outlaw who has
informed the board of his intention to retire May 31, 2001 in accordance with
his contract. Mr. Outlaw will continue to serve on the board of directors.
Liquidity and Capital Resources
Our sources of liquidity and capital resources historically have been net
cash provided by operating activities, funds available under our financing
facilities and proceeds from offerings of debt and equity securities. In the
past, these sources have been sufficient to meet our needs and finance the
growth of our business. We can give no assurance that the historical sources of
liquidity and capital resources will be available for future development and
acquisition projects, and we may be required to seek alternative financing
sources. In 1999, we completed the sales of our Giddings, Katy and MiVida
facilities. In December 1999, we contracted for the sale of the Black Lake
facility and related reserves. This sale closed in January 2000. In 2000, we
sold the stock of our subsidiary, Western Gas Resources-California, Inc. and our
Arkoma gathering system for a combined pre-tax gain of approximately $9.3
million. We contracted for the sale of the stock in our wholly-owned subsidiary
Pinnacle Gas Treating, Inc. in December 2000 for gross proceeds of approximately
$38.0 million. This sale closed
22
in January 2001. We used the proceeds from these sales of approximately $230.9
million to reduce debt. Primarily as a result of these sales, we have reduced
our total outstanding debt from $504.9 million at December 31, 1998 to $320.0
million at January 31, 2001. Product prices, sales of inventory, the volumes of
natural gas processed by our facilities, the volumes of natural gas produced
from our reserves, the margin on third-party product purchased for resale, as
well as the timely collection of our receivables will affect net cash provided
by operating activities in the future. Our future growth will be dependent upon
obtaining additions to dedicated plant reserves, increasing our production,
completing acquisitions, developing new projects, operating our facilities
efficiently and obtaining financing at favorable terms.
We believe that the amounts available to be borrowed under the Revolving
Credit Facility, together with net cash provided by operating activities and the
sale of non-strategic assets, will provide us with sufficient funds to connect
new reserves, maintain our existing facilities, complete our current capital
expenditure program and make any scheduled debt principal payments. Depending on
the timing and the amount of our future projects, we may be required to seek
additional sources of capital. Our ability to secure additional capital is in
some cases restricted by our financing facilities, although we may request
additional borrowing capacity from our lenders, seek waivers from our lenders to
permit us to borrow funds from third parties, seek replacement financing
facilities from other lenders, use stock as a currency for acquisitions, sell
existing assets or a combination of alternatives. While we believe that we would
be able to secure additional financing, if required, we can provide no assurance
that we will be able to do so or as to the terms of any additional financing. We
also believe that cash provided by operating activities and amounts available
under our Revolving Credit Facility will be sufficient to meet our debt service
and preferred stock dividend requirements for 2001 and 2002.
While several of our plants have experienced declines in dedicated reserves,
overall we have been successful in connecting additional reserves to more than
offset the natural declines. Higher gas prices, greater demand for natural gas,
improved technology, e.g., 3-D seismic, well fracturing and horizontal drilling,
and increased pipeline capacity from the Rocky Mountain region have stimulated
drilling in many of our operating areas. The overall level of drilling will
depend upon, among other factors, the prices for oil and gas, the drilling
budgets of third-party producers, the energy and environmental policy and
regulation by governmental agencies and the availability of foreign oil and gas,
none of which is within our control. There is no assurance that we will continue
to be successful in replacing the dedicated reserves processed at our
facilities.
We have 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 those
securities are convertible, and $62 million of debt securities, preferred stock
or common stock.
Our sources and uses of funds for the year ended December 31, 2000 are
summarized as follows (dollars in thousands):
Sources of funds:
Borrowings under Revolving Credit Facility.............................. $ 1,399,736
Proceeds from the dispositions of property and equipment................ 26,484
Net cash provided by operating activities............................... 116,262
Proceeds from exercise of common stock options.......................... 2,680
Other................................................................... 13
-------------
Total sources of funds.............................................. $ 1,545,175
=============
Uses of funds:
Payments related to long-term debt (including debt issue costs)......... $ (1,392,907)
Capital expenditures.................................................... (108,536)
Dividends paid.......................................................... (16,877)
Re-purchase of $2.28 Cumulative Perpetual Preferred Stock............... (990)
Early extinguishment of 1995 Senior debt................................ (27,000)
-------------
Total uses of funds................................................. $ (1,546,310)
=============
23
Additional sources of liquidity available to us are our inventories of gas
and NGLs in storage facilities. We store gas and NGLs primarily to ensure an
adequate supply for long-term sales contracts and for resale during periods when
prices are favorable. We held gas in storage and in imbalances of approximately
10.9 Bcf at an average cost of $3.88 per Mcf at December 31, 2000 compared to
13.7 Bcf at an average cost of $2.40 per Mcf at December 31, 1999 under storage
contracts at various third-party facilities. At December 31, 2000, we had
hedging contracts in place for anticipated sales of approximately 10.7 Bcf of
stored gas at a weighted average price of $4.69 per Mcf for the stored
inventory. See "Item 1 and 2 - Business and Properties - Significant
Acquisitions, Projects and Dispositions - Katy."
We held NGLs in storage under exchange agreements of 6,229 MGal, consisting
primarily of propane and normal butane, at an average cost of $.49 per gallon
and 8,600 MGal, consisting primarily of propane and normal butane, at an average
cost of $.34 per gallon at December 31, 2000 and 1999, respectively. At December
31, 2000, we had no significant hedging contracts in place for these volumes.
Preferred Stock Repurchase Program
In the fourth quarter of 2000, we purchased in open market transactions a
total of 39,190 shares of our $2.28 cumulative preferred stock for a total cost,
including broker commissions, of approximately $1.0 million, or an average of
$25.52 per share of preferred stock. These shares will be retired. Our board of
directors has authorized the re-purchase from time to time of up to an
additional $1.0 million of preferred stock in open market transactions.
Capital Investment Program
Primarily as a result of additional drilling behind our systems and in the
Powder River basin, we increased our capital budget for the year ending December
31, 2000 by approximately $15.8 million from our 2000 original budget. Capital
expenditures related to existing operations totaled approximately $108.5 million
during 2000, consisting of the following: (i) approximately $55.1 million
related to gathering, processing and pipeline assets, of which $5.4 million was
for maintaining existing facilities and $9.3 million for acquisition of the
remaining 50% interest in the Westana Gathering Company; (ii) approximately
$51.6 million related to exploration and production activities; and (iii)
approximately $1.8 million for miscellaneous items. Overall, capital
expenditures in the Powder River basin coal bed methane development and in
southwest Wyoming operations represented 55% and 7%, respectively, of our total
capital expenditures in 2000.
We expect capital expenditures related to existing operations to be
approximately $136.4 million during 2001, consisting of the following: (i)
approximately $71.8 million related to gathering, processing and pipeline
assets, of which $8.5 million is for maintaining existing facilities; (ii)
approximately $56.9 million related to exploration and production activities;
and (iii) approximately $7.7 million for miscellaneous items. Overall, capital
expenditures in the Powder River basin coal bed methane development and in
southwest Wyoming operations represent 49% and 10%, respectively, of the total
2001 budget. This budget will be increased to provide for acquisitions if
approved by our board of directors.
Financing Facilities
Revolving Credit Facility. The Revolving Credit Facility is with a syndicate
of banks and provides for a maximum borrowing commitment of $250 million
consisting of an $83 million 364-day Revolving Credit Facility, or Tranche A,
and a four-year $167 million Revolving Credit Facility, or Tranche B. At
December 31, 2000, $53.7 million in total was outstanding on this facility. The
Revolving Credit Facility bears interest at certain spreads over the Eurodollar
rate, or the greater of the Federal Funds rate or the agent bank's prime rate.
We have the option to determine which rate will be used. We also pay a facility
fee on the commitment. The interest rate spreads and facility fee are adjusted
based on our debt to capitalization ratio and range from .75% to 2.00%. At
December 31, 2000, the interest rate payable on the facility was 8.2%. We are
required to maintain a total debt to capitalization ratio of not more than 60%
through December 31, 2000 and of not more than 55% thereafter, and a senior debt
to capitalization ratio of not more than 40% through December 31, 2001 and of
not more than 35% thereafter. The agreement also requires a quarterly test of
the ratio of EBITDA (excluding some non-recurring items) for the last four
quarters, to interest and dividends on preferred stock for the same period. The
ratio must exceed 1.80 to 1.0 through September 30, 2001 and increases
periodically to 3.25 to 1.0 by December 31, 2002. This facility is guaranteed by
and secured via a pledge of the stock of our significant subsidiaries. We
generally utilize excess daily funds to reduce any outstanding balances on the
Revolving Credit Facility and associated interest expense.
24
Master Shelf Agreement. In December 1991, we entered into a Master Shelf
Agreement with The Prudential Insurance Company of America. Amounts outstanding
under the Master Shelf Agreement at December 31, 2000 are as indicated in the
following table (dollars in thousands):
Interest Final
Issue Date Amount Rate Maturity Principal Payments Due
- --------------------- --------- --------- -------------------- ------------------------------------------------
October 27, 1992 $ 25,000 7.99% October 27, 2003 $8,333 on each of October 27, 2001 through 2003
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
---------
$ 150,000
=========
In 1999, we amended our agreement with Prudential to reflect the following
provisions. We are required to maintain a current ratio, as defined therein, of
at least .9 to 1.0, a minimum tangible net worth equal to the sum of $300
million plus 50% of consolidated net earnings earned from January 1, 1999 plus
75% of the net proceeds of any equity offerings after January 1, 1999, a total
debt to capitalization ratio of not more than 60% through December 31, 2001 and
of not more than 55% thereafter and a senior debt to capitalization ratio of not
more than 40% through March 2002 and not more than 35% thereafter. This
agreement also requires an EBITDA to interest ratio of not less than 2.50 to 1.0
increasing to a ratio of not less than 3.75 to 1.0 by March 31, 2002 and an
EBITDA to interest on senior debt ratio of not less than 4.00 to 1.0 increasing
to a ratio of not less than 5.50 to 1.0 by March 31, 2002. EBITDA in these
calculations excludes certain non-recurring items. In addition, this agreement
contains a calculation limiting dividends under which approximately $64.1
million was available at December 31, 2000. We are currently paying an annual
fee of 0.50% on the amounts outstanding on the Master Shelf Agreement. This fee
will continue until we receive an implied investment grade rating on our senior
secured debt. Borrowings under the Master Shelf Agreement are guaranteed by and
secured via a pledge of the stock of our significant subsidiaries.
1995 Senior Notes. In 1995, we sold $42.0 million of Senior Notes, the 1995
Senior Notes, to a group of insurance companies with an interest rate of 8.16%
per annum. In March 1999, we prepaid $15.0 million of the principal amount
outstanding on the 1995 Senior Notes at par. The remaining principal amount
outstanding of $27.0 million was prepaid in September 2000 with funds available
under the Revolving Credit Facility. In connection with the prepayment in 2000,
we paid a pre-tax make-whole payment of approximately $2.0 million and expensed
capitalized fees of approximately $752,000. The combined costs of approximately
$2.8 million, net of a tax benefit of $997,000, are reflected as an
extraordinary charge on early extinguishment of debt in the year ended December
31, 2000.
Senior Subordinated Notes. In 1999, we sold $155.0 million of Senior
Subordinated Notes in a private placement with a final maturity of 2009 due in a
single payment which were subsequently exchanged for registered publicly
tradable notes under the same terms and conditions. The Subordinated Notes bear
interest at 10% and were priced at 99.225% to yield 10.125%. These notes contain
maintenance covenants which include limitations on debt incurrence, restricted
payments, liens and sales of assets. The Subordinated Notes are unsecured and
are guaranteed on a subordinated basis by some of our subsidiaries. We incurred
approximately $5.0 million in offering commissions and expenses which have been
capitalized and will be amortized over the term of the notes.
Covenant Compliance. We were in compliance with all covenants in our debt
agreements at December 31, 2000. Taking into account all the covenants contained
in these agreements, we had approximately $156 million of available borrowing
capacity at December 31, 2000.
Risk Management Activities
Our commodity price risk management program has two primary objectives. The
first goal is to preserve and enhance the value of our 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 our operating
budget. The second goal is to manage price risk related to our gas, crude oil
and NGL marketing activities to protect profit margins. This risk relates to
hedging fixed
25
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.
We utilize 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, or OTC, market to accomplish these objectives.
These instruments allow us to preserve value and protect margins because
corresponding losses or gains in the value of the financial instruments offset
gains or losses in the physical market.
We use 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 natural gas primarily due to the geographic price differentials
between cash market locations and futures contract delivery locations.
We enter into futures transactions on the New York Mercantile Exchange, or
NYMEX, and the Kansas City Board of Trade and through OTC swaps and options with
various counterparties, consisting primarily of financial institutions and other
natural gas companies. We conduct our standard credit review of OTC
counterparties and have agreements with these parties that contain collateral
requirements. We generally use standardized swap agreements that allow for
offset of positive and negative exposures. OTC exposure is marked-to-market
daily for the credit review process. Our OTC credit risk exposure is partially
limited by our ability to require a margin deposit from our major counterparties
based upon the mark-to-market value of their net exposure. We are subject to
margin deposit requirements under these same agreements. In addition, we are
subject to similar margin deposit requirements for our NYMEX counterparties
related to our net exposures.
The use of financial instruments may expose us to the risk of financial loss
in certain circumstances, including instances when (i) equity volumes are less
than expected, (ii) our customers fail to purchase or deliver the contracted
quantities of natural gas or NGLs, or (iii) our OTC counterparties fail to
perform. To the extent that we engage in hedging activities, we may be prevented
from realizing the benefits of favorable price changes in the physical market.
However, we are similarly insulated against decreases in these prices.
For 2001, we have entered into hedging positions for approximately 47,000
MMbtu per day of our equity gas volumes at an average of $4.30 per MMbtu. We
have hedged an additional 10,000 MMbtu per day of equity gas in the first
quarter of 2001 with a collar providing for a minimum price of $2.75 per MMbtu
and a maximum price of $3.50 per MMbtu. These positions represent approximately
48 percent of our projected equity gas volumes in 2001. Additionally, we have
placed floors on approximately 10,000 barrels per day of our equity production
of crude, condensate and NGLs at a net equivalent minimum oil price of $24.00
per barrel. This represents approximately 63 percent of our forecasted 2001 NGL
production. All prices are NYMEX-equivalents.
For 2002, we have hedged approximately 40,000 MMbtus per day, or 27 percent
of our projected equity gas production, with collar structures providing for an
average minimum price of $3.63 per MMbtu and an average maximum price of $6.11
per MMbtu. These prices are NYMEX-equivalents. We have not hedged any equity NGL
volumes in 2002.
At December 31, 2000 we had $695,000 of gains unrecognized in inventory that
will be recognized primarily during the first quarter of 2001 which may be
partially offset by losses from our related forward fixed price hedges and
physical sales. At December 31, 2000 we had unrecognized net losses of $804,000
related to financial instruments that are expected to be offset by corresponding
unrecognized net gains from our obligations to sell physical quantities of gas
and NGLs.
We enter into speculative futures, swap and option trades on a very limited
basis for purposes that include testing of hedging techniques. Our 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 or losses from such
speculative activities for the years ended December 31, 2000 and 1999 were not
material.
Natural Gas Derivative Market Risk. As of December 31, 2000, we held a
notional quantity of approximately 291 Bcf of natural gas futures, swaps and
options extending from January 2001 to December 2002 with a weighted average
duration of approximately 4.4 months. This was comprised of approximately 116
Bcf of long positions and 175 Bcf of short positions in these instruments. As of
December 31, 1999, we held a notional quantity of approximately 202 Bcf of
natural gas futures,
26
swaps and options extending from January 2000 to January 2001 with a weighted
average duration of approximately three months. This was comprised of
approximately 87 Bcf of long positions and 115 Bcf of short positions in these
instruments.
We use a Value-at-Risk (VaR) model designed by J.P. Morgan as one measure of
market risk for our natural gas portfolio. The VaR calculated by this model
represents the maximum change in market value over the holding period at the
specified statistical confidence interval. The VaR model is generally based upon
J.P. Morgan's RiskMetrics (TM) methodology using historical price data to derive
estimates of volatility and correlation for estimating the contribution of tenor
and location risk. The VaR model assumes a one day holding period and uses a 95%
confidence level.
As of December 31, 2000, the calculated VaR of our entire natural gas
portfolio of futures, swaps and options was approximately $4.4 million. This
figure includes the risk related to our entire portfolio of natural gas
financial instruments and does not include the related underlying hedged
physical transactions.
All financial instruments for which there are no offsetting physical
transactions are treated as either the hedge of an anticipated transaction or a
speculative trade. As of December 31, 2000, the VaR of these type of
transactions for natural gas was approximately $173,000.
Crude Oil and NGL Derivative Market Risk. As of December 31, 2000, we held
a notional quantity of approximately 156,240 MGal of NGL futures, swaps and
options extending from January 2001 to December 2002 with a weighted average
duration of approximately 6.5 months. This was comprised of approximately
156,240 MGal of long positions in these instruments. As of December 31, 1999, we
held a notional quantity of approximately 123,500 MGal of NGL futures, swaps and
options extending from January 2000 to December 2000 with a weighted average
duration of approximately seven months. This was comprised of approximately
110,000 MGal of long positions and 12,000 MGal of short positions in these
instruments.
As of December 31, 2000, we had purchased puts for 125,000 barrels per month
of NYMEX monthly average settlement of $23.96 per barrel to hedge a portion of
the Company's equity production of natural gasoline, condensates, butanes and
crude oil. We do not hold any crude oil futures, swaps or options for settlement
beyond 2001.
As of December 31, 2000, we had purchased puts for 125,000 barrels per month
of OPIS Mt. Belvieu monthly average settlement of $.434 per gallon to hedge a
portion of our equity production of propane for 2001.
As of December 31, 2000, we had purchased puts for 60,000 barrels per month
of OPIS Mt. Belvieu monthly average settlement of $.3175 per gallon of purity
ethane to hedge a portion of our equity production of ethane for 2001.
As of December 31, 2000, we did not hold any NGL futures, swaps or options
for settlement beyond 2001. As of December 31, 2000, the estimated fair value of
the aforementioned crude oil and NGL options held by us was approximately $4.4
million.
Foreign Currency Derivative Market Risk. As a normal part of our business,
we enter into physical gas transactions which are payable in Canadian dollars.
We enter into forward purchases and sales of Canadian dollars from time to time
to fix the cost of our future Canadian dollar denominated natural gas purchase,
sale, 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 the commitment for the payment obligation is made and the
actual payment date of such obligation. As of December 31, 2000, the net
notional value of such contracts was approximately $17.9 million in Canadian
dollars, which approximates its fair market value. As of December 31, 1999, the
net notional value of such contracts was approximately $7.5 million in Canadian
dollars, which approximated its fair market value.
Accounting for Derivative Instruments and Hedging Activities. In June 1998,
the Financial Accounting Standards Board, the FASB, issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS No. 133"),
effective for fiscal years beginning after June 15, 2000. Under SFAS No. 133,
which was subsequently amended by SFAS No. 138, we will be required to recognize
the change in the market value of all derivatives as either assets or
liabilities in the statement of financial position and measure those instruments
at fair value. Changes in the fair value of derivatives are recorded each period
in current earnings or other comprehensive income depending upon the nature of
the underlying transaction. Upon adoption of SFAS No. 133 on January 1, 2001,
the impact from our hedging activities was a decrease in a component of
stockholders' equity through Accumulated other comprehensive income of $25.7
million, an increase to Current assets of $671,000, an
27
increase to Current liabilities of $40.4 million, an increase in Other long-term
liabilities of $849,000 and an increase in Deferred income taxes payable of
$14.8 million. We adopted mark to market accounting in the first quarter of 2001
for the remainder of our marketing activities which for various reasons are not
designated or qualified as hedges under SFAS 133. Upon adoption of mark to
market accounting for our marketing activities on January 1, 2001, the impact
was a net increase to pre-tax income through an unrealized gain of $5.1 million,
an increase to Current assets of $52.0 million, an increase to Current
liabilities of $46.6 million and an increase to Other long-term liabilities of
$343,000.
Environmental
The construction and operation of our gathering systems, 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 our facilities or at facilities to which we send wastes for
disposal. In most instances, the applicable regulatory requirements relate to
water and air pollution control or waste management. We employ four
environmental engineers, four safety specialists and three regulatory compliance
specialists to monitor environmental and safety compliance at our facilities.
Prior to consummating any major acquisition, our environmental engineers perform
audits on the facilities to be acquired. In addition, on an ongoing basis, the
environmental engineers perform environmental assessments of our existing
facilities. We believe that we are in substantial compliance with applicable
material environmental laws and regulations. Environmental regulation can
increase the cost of planning, designing, constructing and operating our
facilities. We believe that the costs for compliance with current environmental
laws and regulations have not had and will not have a material effect on our
financial position or results of operations.
The Texas Natural Resource Conservation Commission which has authority to
regulate, among other things, stationary air emissions sources, has created a
committee to make recommendations to the Commission regarding a voluntary
emissions reduction plan for the permitting of existing "grand-fathered" air
emissions sources within Texas. A "grand-fathered" air emissions source is one
that does not need a state operating permit because it was constructed prior to
1971. We operate a number of these sources within Texas, including portions of
our Midkiff/Benedum, Gomez and Mitchell Puckett systems. In connection with a
modernization program, we are replacing all of our "grand-fathered" compressors
in Texas and expect to complete this process in 2001. Other "grand-fathered"
sources, if not permitted or modified, may be subject to increasing emissions
fees beginning in 2002. We do not believe that such increases will have a
material effect on our financial position or results of operations.
We anticipate that it is reasonably likely that the trend in environmental
legislation and regulation will continue to be towards stricter standards. We
are unaware of future environmental standards that are reasonably likely to be
adopted that will have a material effect on our financial position or results of
operations, but we cannot rule out that possibility.
We are in the process of voluntarily cleaning up substances at certain
facilities that we operate. Our expenditures for environmental evaluation and
remediation at existing facilities have not been significant in relation to our
results of operations and totaled approximately $2.4 million for the year ended
December 31, 2000, including approximately $417,000 in air emissions fees to the
states in which we operate. Although we anticipate that such environmental
expenses per facility will increase over time, we do not believe that such
increases will have a material effect on our financial position or results of
operations.
28
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements
Western Gas Resources, Inc.'s Consolidated Financial Statements as of December
31, 2000 and 1999 and for each of the three years in the period ended December
31, 2000:
Page
----
Report of Management..................................................................................... 30
Report of Independent Accountants........................................................................ 31
Consolidated Balance Sheet............................................................................... 32
Consolidated Statement of Cash Flows..................................................................... 33
Consolidated Statement of Operations..................................................................... 34
Consolidated Statement of Changes in Stockholders' Equity................................................ 35
Notes to Consolidated Financial Statements............................................................... 36
29
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 PricewaterhouseCoopers 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.
/S/ L. F. Outlaw
- -------------------------------------------------
L. F. Outlaw
Chief Executive Officer and President
/S/ William J. Krysiak
- -------------------------------------------------
William J. Krysiak
Vice President - Finance (Principal Financial and
Accounting Officer)
30
REPORT OF INDEPENDENT ACCOUNTANTS
- ---------------------------------
To the Board of Directors and
Stockholders of Western Gas Resources, Inc.
In our opinion, the consolidated financial statements listed in the accompanying
index present fairly, in all material respects, the financial position of
Western Gas Resources, Inc. and its subsidiaries at December 31, 2000 and 1999,
and the results of their cash flows and their operations for each of the three
years in the period ended December 31, 2000 in conformity with accounting
principles generally accepted in the United States of America. 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
auditing standards generally accepted in the United States of America, 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 our opinion expressed above.
PricewaterhouseCoopers LLP
Denver, Colorado
February 23, 2001
31
WESTERN GAS RESOURCES, INC.
CONSOLIDATED BALANCE SHEET
(000s, except share data)
December 31,
------------------------------
ASSETS 2000 1999
------ ------------ ------------
Current assets:
Cash and cash equivalents......................................................... $ 12,927 $ 14,062
Trade accounts receivable, net.................................................... 546,791 196,739
Product inventory................................................................. 44,822 35,228
Parts inventory................................................................... 3,489 10,318
Assets held for sale.............................................................. 25,001 7,237
Other ............................................................................ 2,654 9,571
------------ ------------
Total current assets........................................................... 635,684 273,155
------------ ------------
Property and equipment:
Gas gathering, processing, storage and transportation............................. 856,982 808,274
Oil and gas properties and equipment (successful efforts method).................. 139,084 104,137
Construction in progress.......................................................... 58,319 39,987
------------ ------------
1,054,385 952,398
Less: Accumulated depreciation, depletion and amortization......................... (306,651) (260,081)
------------- -------------
Total property and equipment, net.............................................. 747,734 692,317
------------ ------------
Other assets:
Gas purchase contracts (net of accumulated amortization of $33,357 and
$31,273, respectively)......................................................... 34,798 36,883
Other ............................................................................ 13,206 47,131
------------ ------------
Total other assets................................................................ 48,004 84,014
------------ ------------
Total assets.......................................................................... $ 1,431,422 $ 1,049,486
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
Current liabilities:
Accounts payable.................................................................. $ 581,563 $ 240,235
Accrued expenses.................................................................. 25,094 41,075
Dividends payable................................................................. 4,205 4,218
------------ ------------
Total current liabilities...................................................... 610,862 285,528
Long-term debt........................................................................ 358,700 378,250
Other long-term liabilities........................................................... 2,646 -
Deferred income taxes payable, net.................................................... 67,680 35,965
------------ ------------
Total liabilities..................................................................... 1,039,888 699,743
------------ ------------
Commitments and contingent liabilities (Note 8)....................................... - -
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; 32,361,131 and
32,186,747 shares issued, respectively ........................................ 3,265 3,220
Treasury stock, at cost; 25,016 common shares and 39,190 $2.28 cumulative
preferred shares in treasury................................................... (1,778) (788)
Additional paid-in capital........................................................ 400,157 397,522
Retained deficit.................................................................. (11,820) (51,064)
Accumulated other comprehensive income............................................ 2,178 1,321
Notes receivable from key employees secured by common stock....................... (884) (884)
------------ ------------
Total stockholders' equity..................................................... 391,534 349,743
------------ ------------
Total liabilities and stockholders' equity............................................ $ 1,431,422 $ 1,049,486
============ ============
The accompanying notes are an integral part of the consolidated financial
statements.
32
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(000s)
Year Ended December 31,
----------------------------------------
2000 1999 1998
----------- ----------- ----------
Reconciliation of net income to net cash provided by operating activities:
Net income (loss)............................................................ $ 56,108 $ (17,124) $ (67,205)
Add income items that do not affect cash:
Depreciation, depletion and amortization................................. 57,919 50,981 59,346
Deferred income taxes.................................................... 32,712 (11,428) (32,722)
Distributions in excess of (less than) equity income, net................ (1,137) (987) 963
(Gain) Loss on the sale of property and equipment........................ (9,406) 29,802 (16,478)
Impairment of property and equipment..................................... - 1,158 108,447
Compensation expense from re-priced stock options........................ 1,879 - -
Other non-cash items, net................................................ 1,804 1,080 2,595
----------- ----------- ----------
139,879 51,322 54,946
----------- ----------- ----------
Adjustments to working capital to arrive at net cash provided by
operating activities:
(Increase) decrease in trade accounts receivable......................... (350,895) 36,567 25,317
(Increase) decrease in product inventory ................................ (9,594) 10,963 (29,810)
Decrease (increase) in parts inventory .................................. 1,612 (165) (748)
Decrease (increase) in other current assets.............................. 3,821 (6,620) (587)
Decrease in other assets and liabilities, net............................ 424 350 257
Increase (decrease) in accounts payable.................................. 348,892 (4,960) (81,381)
(Decrease) increase in accrued expenses.................................. (17,877) 7,727 (3,564)
----------- ----------- ----------
Total adjustments..................................................... (23,617) 43,862 (90,516)
----------- ----------- ----------
Net cash provided by (used in) operating activities.......................... 116,262 95,184 (35,570)
----------- ----------- ----------
Cash flows from investing activities:
Purchases of property and equipment, including acquisitions.............. (108,536) (80,089) (104,171)
Proceeds from the disposition of property and equipment.................. 26,484 148,685 75,286
Contributions to equity investees........................................ - (1,400) (1,045)
Distributions from equity investees...................................... 13 88 3,489
----------- ----------- ----------
Net cash provided by (used in) investing activities.......................... (82,039) 67,284 (26,441)
----------- ----------- ----------
Cash flows from financing activities:
Net proceeds from exercise of common stock options....................... 2,680 158 23
Payments for the re-purchase of preferred stock.......................... (990) - -
Proceeds from issuance of long-term debt................................. - 155,000 -
Payments on long-term debt............................................... (27,000) (92,380) (15,476)
Borrowings under revolving credit facility............................... 1,399,736 2,115,250 3,230,400
Payments on revolving credit facility.................................... (1,392,286) (2,304,500) (3,151,400)
Debt issue costs paid.................................................... (621) (9,469) (44)
Dividends paid .......................................................... (16,877) (16,865) (16,869)
----------- ----------- ----------
Net cash provided by (used in) financing activities.......................... (35,358) (152,806) 46,634
----------- ----------- ----------
Net increase (decrease) in cash and cash equivalents......................... (1,135) 9,662 (15,377)
Cash and cash equivalents at beginning of year............................... 14,062 4,400 19,777
----------- ----------- ----------
Cash and cash equivalents at end of year .................................... $ 12,927 $ 14,062 $ 4,400
=========== =========== ==========
The accompanying notes are an integral part of the consolidated financial
statements.
33
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
(000s, except share and per share amounts)
Year Ended December 31,
-----------------------------------------
2000 1999 1998
------------ ------------ ------------
Revenues:
Sale of gas................................................................ $ 2,624,409 $ 1,501,066 $ 1,611,521
Sale of natural gas liquids................................................ 590,936 346,819 449,696
Processing, transportation and storage revenue............................. 53,156 48,994 44,743
Other .................................................................... 13,487 13,845 11,128
------------ ------------ ------------
Total revenues......................................................... 3,281,988 1,910,724 2,117,088
------------ ------------ ------------
Costs and expenses:
Product purchases.......................................................... 2,985,501 1,715,839 1,914,303
Plant operating expense.................................................... 69,892 67,419 85,353
Oil and gas exploration and production costs............................... 19,521 9,196 7,996
Depreciation, depletion and amortization .................................. 57,919 50,981 59,346
Selling and administrative expense......................................... 33,717 28,357 30,128
(Gain) loss on sale of assets.............................................. (9,406) 29,802 (16,478)
Interest expense........................................................... 33,460 33,156 33,616
Loss on the impairment of property and equipment........................... - 1,158 108,447
------------ ------------ ------------
Total costs and expenses............................................... 3,190,604 1,935,908 2,222,711
------------ ------------ ------------
Income (loss) before income taxes............................................. 91,384 (25,184) (105,623)
Provision (benefit) for income taxes:
Current ................................................................... 850 2,261 (5,696)
Deferred ................................................................. 32,712 (11,428) (32,722)
------------ ------------ ------------
Total provision (benefit) for income taxes............................. 33,562 (9,167) (38,418)
------------ ------------ ------------
Income (loss) before extraordinary items...................................... 57,822 (16,017) (67,205)
Extraordinary charge for early extinguishment of debt,
net of tax benefit of $997,000 and $628,000, respectively.............. (1,714) (1,107) -
------------ ------------ ------------
Net income (loss)............................................................. $ 56,108 $ (17,124) $ (67,205)
------------ ------------- ------------
Preferred stock requirements.................................................. (10,416) (10,439) (10,439)
------------ ------------ ------------
Net income (loss) attributable to common stock................................ $ 45,692 $ (27,563) $ (77,644)
============ ============ ============
Net income (loss) per share of common stock before extraordinary item......... $ 1.47 $ (.83) $ (2.42)
============ ============ ============
Extraordinary item............................................................ $ (.05) $ (.03) $ -
============ ============ ============
Net income (loss) per share of common stock................................... $ 1.42 $ (.86) $ (2.42)
============ ============ ============
Weighted average shares of common stock outstanding........................... 32,240,755 32,150,887 32,147,354
============ ============ ============
Net income (loss) per share of common stock - assuming dilution............... $ 1.39 $ (.86) $ (2.42)
============ ============ ============
Weighted average shares of common stock outstanding - assuming dilution....... 32,834,641 32,150,887 32,147,354
============ ============ ============
The accompanying notes are an integral part of the
consolidated financial statements.
34
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
(000s, except share amounts)
Shares of $2.625 Shares of $2.625
$2.28 Cumulative Shares $2.28 $2.28 Cumulative
Cumulative Convertible Shares of Common Cumulative Cumulative Convertible
Preferred Preferred of Common Stock Preferred Stock Preferred Preferred
Stock Stock Stock in Treasury in Treasury Stock Stock
---------- ------------ ---------- -------------- -------------- ---------- ----------
Balance at December 31, 1997 ............ 1,400,000 2,760,000 32,146,437 25,016 - $ 140 $ 276
Comprehensive Comprehensive income:
Net income, 1998 ..................... - - - - - - -
Translation Adjustments .............. - - - - - - -
Stock options exercised ................. - - 1,556 - - - -
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, 1998 ............ 1,400,000 2,760,000 32,147,993 25,016 - 140 276
Comprehensive income:
Net income, 1999 ..................... - - - - - - -
Translation adjustments .............. - - - - - - -
Stock options exercised ................. - - 13,738 - - - -
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, 1999 ............ 1,400,000 2,760,000 32,161,731 25,016 - 140 276
Comprehensive income:
Net income, 2000 ..................... - - - - - - -
Translation adjustments .............. - - - - - - -
Stock options exercised ................. - - 199,400 - - - -
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 .......... - - - - - - -
Repurchase of $2.28 cumulative
preferred stock ...................... - - - - 39,190 - -
---------- --------- ---------- -------- -------- ------- --------
Balance at December 31, 2000 ............ 1,400,000 2,760,000 32,361,131 25,016 39,190 $ 140 $ 276
=========== ========= =========== ========== ======= ======= ========
Accumulated
Other Notes Total
Additional Retained Comprehensive Receivable Stock-
Common Treasury Paid-In (Deficit) Income from Key holders'
stock Stock Capital Earnings Net of Tax Employees Equity
----------- ----------- --------- ----------- ---------- ---------- ---------
Balance at December 31, 1997 ............ $ 3,217 $ (788) $ 397,321 $ 66,999 $ 2,233 $ (1,286) $ 468,112
Comprehensive income:
Net income, 1998 ..................... - - - (67,205) - - (67,205)
Translation Adjustments .............. - - - - 820 - 820
Stock options exercised ................. - - 23 - - - 23
Loans forgiven .......................... - - - - - 335 335
Dividends declared on common stock ...... - - - (6,430) - - (6,430)
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, 1998 ............ 3,217 (788) 397,344 (17,075) 3,053 (951) 385,216
Comprehensive income:
Net income, 1999 ..................... - - - (17,124) - - (17,124)
Translation adjustments .............. - - - - (1,732) - (1,732)
Stock options exercised ................. 3 - 155 - - - 158
Tax benefit related to stock options .... - - 23 - - - 23
Loans forgiven .......................... - - - - - 67 67
Dividends declared on common stock ...... - - - (6,426) - - (6,426)
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, 1999 ............ 3,220 (788) 397,522 (51,064) 1,321 (884) 349,743
Comprehensive income:
Net income, 2000 ..................... - - - 56,108 - - 56,108
Translation adjustments .............. - - - - 857 - 857
Stock options exercised ................. 45 - 2,635 - - - 2,680
Tax benefit related to stock options .... - - - - - - -
Loans forgiven .......................... - - - - - - -
Dividends declared on common stock ...... - - - (6,448) - - (6,448)
Dividends declared on $2.28 cumulative
preferred stock ...................... - - - (3,171) - - (3,171)
Dividends declared on $2.625 cumulative
convertible preferred stock .......... - - - (7,245) - - (7,245)
Repurchase of $2.28 cumulative
preferred stock ...................... - (990) - - - - (990)
----------- ---------- ------------ ----------- -------- ---------- ---------
Balance at December 31, 2000 ............ $ 3,265 $ (1,778) $ 400,157 $ (11,820) $ 2,178 $ (884) $ 391,534
========== ========== ============ =========== ======== ========== =========
The accompanying notes are an integral part of the consolidated financial
statement
35
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 1 - NATURE OF ORGANIZATION
- -------------------------------
Western Gas Resources, Inc. (the "Company") designs, constructs, owns and
operates natural gas gathering systems and facilities for the processing and
treating of natural gas and NGLs. The Company also transports and markets
natural gas and NGLs from these facilities in order to provide its customers
with a broad range of services from the wellhead to the sales delivery point.
The Company operates in major gas-producing basins in the Rocky Mountain,
Mid-Continent, Gulf Coast and Southwestern regions of the United States. The
Company also has the drilling rights on substantial acreage positions located
primarily in Wyoming and explores for, develops and produces natural gas.
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
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 Company has also completed two public offerings of preferred stock. 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 the fourth quarter of 2000, the board of directors of the Company
authorized the re-purchase in open market transactions of up to $2.0 million of
the $2.28 Cumulative Preferred Stock. Through December 31, 2000, the Company had
re-purchased 39,190 of these shares for a total consideration of approximately
$1.0 million. 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 continues to expand its Powder River basin coal
bed methane natural gas gathering system and develop its own coal seam gas
reserves in Wyoming. During the years ended December 31, 2000, 1999 and 1998,
the Company expended approximately $59.1 million, $51.4 million and $46.7
million, respectively, on this project.
In December 1998, the Company joined with other industry participants to form
the Fort Union Gas Gathering, L.L.C., to construct a gathering pipeline and
treater in the Powder River basin in northeast Wyoming. The Company owns an
approximate 13% interest in Fort Union and is the construction manager and field
operator. The gathering pipeline went into service in the third quarter of 1999.
Construction of the gathering header and treating system was project financed
and required a cash investment by the Company of approximately $900,000. In
conjunction with the project financing, the Company entered into a ten year
agreement for firm gathering services on 60 MMcf/D of capacity for $.14 per Mcf
on Fort Union beginning in December 1999. In the fourth quarter of 2000, the
Company and other participants in the Fort Union Gas Gathering, L.L.C. approved
an expansion of the system. Construction of the expansion is expected to be
completed in the third quarter of 2001. This expansion, which is anticipated to
cost $25.7 million, will be project financed and will require an additional cash
investment by the Company of approximately $500,000. Also in connection with the
expansion, the Company will increase its commitment for firm gathering services
by an additional 23 MMcf/D of capacity at $.14 per Mcf.
36
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Southwest Wyoming. The Company's facilities in southwest Wyoming are comprised
of the Granger and Lincoln Road facilities (collectively the "Granger Complex")
and the Red Desert facility. During the years ended December 31, 2000, 1999 and
1998, the Company expended approximately $8.0 million, $12.4 million and $16.0
million, respectively, in this area. In February 1998, the Company sold a 50%
undivided interest in a small portion of the Granger gathering system for
approximately $4.0 million. This amount approximated the Company's cost in such
facilities. In December 2000, the Company acquired the remaining 28% interest in
the Lincoln Road facility for $2.6 million.
Pinnacle Gas Treating, Inc. In 1996 and 1997, the Pinnacle Reef exploration area
was rapidly developing into a very active lease acquisition and exploratory
drilling area using 3-D seismic technology to identify prospects. The initial
discoveries indicated a very large potential gas development. Based on the
receipt of large acreage dedications in this area, the Company, through its
wholly-owned subsidiary Pinnacle Gas Treating, Inc. ("Pinnacle"), constructed
the Bethel treating facility for a total cost of approximately $102.8 million
with a throughput capacity of 300 MMcf/D. In 1998, the production rates from the
wells drilled in this field and the recoverable reserves from these properties,
were far less than the producers originally expected. In the fourth quarter of
1998, because of uncertainties related to the pace and success of third-party
drilling programs, declines in volumes produced at certain wells and other
conditions outside of the Company's control, the Company determined that a
pre-tax, non-cash impairment charge of $77.8 million was required.
In December 2000, the Company signed an agreement with Anadarko Petroleum
Corporation for the sale of the stock of Pinnacle for approximately $38.0
million. The sale closed in January 2001 and resulted in an approximate pre-tax
gain for financial reporting purposes of $12.1 million, subject to final
accounting adjustments. The assets of Pinnacle are reflected on the Consolidated
Balance Sheet at December 31, 2000 as Assets held for sale. The proceeds from
this transaction were used to reduce amounts outstanding under the Company's
Revolving Credit Facility.
Arkoma. In August 2000, the Company sold its Arkoma Gathering System in Oklahoma
for gross proceeds of $10.5 million. This sale resulted in an approximate
pre-tax gain of $3.9 million.
Westana Gathering Company. In February 2000, the Company acquired the remaining
50% interest in the Westana Gathering Company ("Westana") for a net purchase
price of $9.8 million. The results from our ownership through February 2000 of a
50% equity interest in Westana are reflected in revenues in Other, net on the
Consolidated Statement of Operations. Beginning in March 2000, the results of
these operations are fully consolidated and are included in Revenues and Costs
and Expenses. Additionally, in March 2000, the Company's investment in Westana
has been reclassified from Other Assets to Property and Equipment.
Western Gas Resources - California, Inc. In January 2000, the Company sold all
of the outstanding stock of its wholly-owned subsidiary Western Gas Resources -
California, Inc. ("WGR California") for $14.9 million. The only asset of this
subsidiary was a 162 mile pipeline in the Sacramento Basin of California. The
pipeline was acquired through the exercise of an option by the Company in a
transaction which closed simultaneously with the sale of WGR California. The
Company recognized a pre-tax gain on the sale of approximately $5.4 million in
the first quarter of 2000.
Black Lake. In December 1999, the Company entered into an agreement for the sale
of its Black Lake facility and related reserves for gross proceeds of $7.8
million, subject to final accounting adjustment. This sale closed in January
2000. This transaction resulted in an approximate pre-tax loss of $7.3 million,
which was recognized in the fourth quarter of 1999.
MiVida. In June 1999, the Company sold its MiVida treating facility for gross
proceeds of $12.0 million, which resulted in an approximate pre-tax gain of $1.2
million.
Giddings. In April 1999, the Company sold its Giddings facility for gross
proceeds of $36.0 million, which resulted in an approximate pre-tax loss of $6.6
million.
37
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Katy. In April 1999, the Company sold all of the outstanding common stock of its
wholly-owned subsidiary, Western Gas Resources Storage, Inc., for gross proceeds
of $100.0 million, which resulted in an approximate pre-tax loss of $17.7
million. The only asset of this subsidiary was the Katy facility. The Company
also sold approximately 5.1 Bcf of stored gas in the Katy facility to the same
purchaser for total sales proceeds of approximately $11.7 million, which
approximated the cost of the inventory. To meet the needs of its marketing
operations, the Company will continue to contract for storage capacity.
Accordingly, the Company entered into a long-term agreement with the purchaser
for 3 Bcf of storage capacity at market rates through March 2002.
Edgewood. In two transactions which closed in October 1998 the Company sold its
Edgewood gathering system, including its undivided interest in the producing
properties associated with this facility, and its 50% interest in the Redman
Smackover Joint Venture. The combined sales price was $55.8 million which
resulted in a pre-tax gain of approximately $1.6 million.
Perkins. In November 1997, the Company entered into an agreement to sell its
Perkins facility. In March 1998, the Company completed the sale of this facility
with an effective date of January 1, 1998. The sales price was $22.0 million and
resulted in a pre-tax gain of approximately $14.9 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.
Principles of Consolidation. The consolidated financial statements include the
accounts of the Company and the Company's wholly-owned subsidiaries. All
material inter-company transactions have been eliminated in consolidation. The
Company's interest in certain investments is accounted for by the equity method.
Inventories. Inventories are recorded at the lower of cost or estimated
realizable value. The cost of gas and NGL inventories is determined by the
weighted average cost method on a location-by-location basis. Residue and NGL
inventory covered by hedging contracts is accounted for on a specific
identification basis. Product inventory includes $9.4 million and $32.8 million
of gas and $.7 million and $2.9 million of NGLs at December 31, 2000 and 1999,
respectively.
Property and Equipment. Property and equipment is recorded at the lower of cost,
including capitalized interest, 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. 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 developed reserves on a property by property
basis.
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 SFAS No. 109, "Accounting
for Income Taxes."
38
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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. The translation
adjustments for the years ended December 31, 2000, 1999 and 1998 were
$(857,000), $(1.7) million and $820,000, respectively, net of tax.
Revenue Recognition. Revenue for sales or services is recognized at the time the
gas or NGLs are delivered or at the time the service is performed.
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 of comprehensive income be reported as a separate
component of stockholders' equity. The Company's cumulative translation
adjustments of $(857,000), $(1.7) million and $820,000 million for the years
ended December 31, 2000, 1999 and 1998 are separately reported on the
Consolidated Statement of Changes in Stockholders' Equity.
Accounting for Derivative Instruments and Hedging Activities. 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 (including hedges of equity production) are recognized
in gas and NGL sales, as reported on the Consolidated Statement of Operations,
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. To the extent the Company engages in
speculative transactions, they are marked to market at the end of each
accounting period and any gain or loss is recognized in income for that period.
Such amounts were negligible in 2000, 1999 and 1998.
In June 1998, the Financial Accounting Standards Board, the FASB, issued SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS
No. 133"), effective for fiscal years beginning after June 15, 2000. Under SFAS
No. 133, which was subsequently amended by SFAS No.138, the Company will be
required to recognize the change in the market value of all derivatives as
either assets or liabilities in the statement of financial position and measure
those instruments at fair value. Changes in the fair value of derivatives are
recorded each period in current earnings or other comprehensive income depending
upon the nature of the underlying transaction. Upon adoption of SFAS No. 133 on
January 1, 2001, the impact was a decrease in a component of stockholders'
equity through Accumulated other comprehensive income of $25.7 million, an
increase to Current assets of $671,000, an increase to Current liabilities of
$40.4 million, an increase in Other long-term liabilities of $849,000 and an
increase in Deferred income taxes payable of $14.8 million. The Company adopted
mark to market accounting in the first quarter of 2001 for the remainder of its
marketing activities which for various reasons are not designated or qualified
as hedges under SFAS 133. Upon adoption of mark to market accounting for its
marketing activities on January 1, 2001, the impact was a net increase to
pre-tax income through an unrealized gain of $5.1 million, an increase to
Current assets of $52.0 million, an increase to Current liabilities of $46.6
million and an increase to Other long-term liabilities of $343,000.
Impairment of Long-Lived Assets. SFAS No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to be Disposed of" ("SFAS No.
121") requires long-lived assets be reviewed whenever events or changes in
circumstances indicate that the carrying value of such assets may not be
recoverable. The Company reviews its assets at the plant facility and oil and
gas producing property levels. 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 net 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 future net 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 $1.2
million and $108.5 million in accordance with SFAS No. 121 during the years
ended December 31, 1999 and 1998, respectively. There were no write-downs in
2000.
39
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Earnings (Loss) Per Share of Common Stock. The Company follows 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 for each of the years ended December 31, 2000, 1999 and 1998,
respectively. Common stock options, which are potential common shares were
anti-dilutive in 1999 and 1998, and therefore were excluded from the
computation. 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
computations for each of the three years in the period ended December 31, 2000
were not adjusted to reflect the conversion of 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, or a reduction
of loss per share, after giving affect to the preferred 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 comprising the Company's customer
base and their dispersion across industries and geographic locations.
With natural gas prices at historically high levels, the Company continually
monitors and reviews the credit exposure to its marketing counter parties. This
review has resulted in a temporary reduction in sales volumes with various
counter parties in order to maintain acceptable credit exposures. During 2000,
the Company reserved approximately $1.6 million for doubtful accounts. There
were no reserves in 1999 or 1998. During the year ended December 31, 2000, the
Company sold gas to a variety of customers including end-users, pipelines, LDCs
and others. One customer accounted for approximately 6% of the Company's
consolidated revenues from the sale of gas, or 5% of total consolidated revenue,
for the year ended December 31, 2000. This customer is a large integrated
utility.
During the year ended December 31, 2000, the Company sold NGLs to a variety of
customers. These customers are end-users, fractionators, chemical companies and
other customers. Three customers accounted for approximately 35% of the
Company's consolidated revenues from the sale of NGLs, or 6% of total
consolidated revenue, for the year ended December 31, 2000. These customers are
all large integrated energy companies.
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 $36.5 million, $34.1
million and $36.1 million, respectively, for the years ended December 31, 2000,
1999 and 1998. Capitalized interest associated with construction of new projects
was $3.4 million, $2.0 million and $2.5 million, respectively, for the years
ended December 31, 2000, 1999 and 1998. Income taxes paid or (refunded) were
$400,000, $(2.9) million and $0, respectively, for the years ended December 31,
2000, 1999 and 1998.
Stock Compensation. As permitted under SFAS No. 123, "Accounting for Stock-Based
Compensation" ("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.
40
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
In March 2000, the FASB issued Interpretation No. 44, an interpretation of APB
Opinion No. 25, "Accounting for Certain Transactions Involving Stock
Compensation," regarding the accounting treatment of re-priced stock options.
This interpretation became effective July 1, 2000. Under this interpretation,
the Company is required to record compensation expense (if not previously
accrued) equal to the number of unexercised re-priced options multiplied by the
amount by which its stock price at the end of any quarter exceeds $21 per share.
The Company had options covering 148,133 common shares outstanding at December
31, 2000 which were treated as re-priced options. Based on the Company's stock
price at December 31, 2000 of $33.69 per share, additional compensation expense
of $1.9 million was recorded in the year ended December 31, 2000.
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 net 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 drilling budgets of third-party producers, the energy policy of
the federal government and the availability of foreign oil and gas, none of
which are within the Company's control.
Reclassifications. Certain prior years' amounts in the consolidated financial
statements and related notes have been reclassified to conform to the
presentation used in 2000.
NOTE 3 - RELATED PARTIES
- ------------------------
From time to time, 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. The Company had a 50% ownership
interest in Williston Gas Company ("Williston"), Westana and a 49% ownership
interest in Sandia Energy Resources Joint Venture. Williston Gas Company was
dissolved in December 1998, Westana was dissolved in February 2000 and Sandia
was dissolved in 1999. The Company acted as operator for Williston and Westana.
All transactions entered into by the Company with its related parties were
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 Westana and charged a monthly overhead fee to cover
such services. The Company provided substantially all of the natural gas that
Sandia marketed and also provided it with various administrative services. In
addition, the Company purchased gas from Sandia.
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. The loan and accrued interest will be forgiven if the employee is
continually employed by the Company and upon a resolution of the board of
directors. As of December 31, 2000 and 1999, loans related to 75,000 shares of
Common Stock totaling $803,000 were outstanding to certain current and past
employees under these programs. Certain of 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 1999, the board of directors approved
the forgiveness of loans to certain individuals totaling approximately $67,000
in connection with these plans. There were no loans forgiven in 2000.
NOTE 4 - COMMODITY RISK MANAGEMENT
- ---------------------------------
41
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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, crude
oil and NGL 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 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 natural 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 various 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.
For 2001, the Company has entered into hedging positions for approximately
47,000 MMbtu per day of its projected equity gas volumes at an average of $4.30
per MMbtu. The Company has hedged an additional 10,000 MMbtu per day of equity
gas in the first quarter of 2001 with a collar providing for a minimum price of
$2.75 per MMbtu and a maximum price of $3.50 per MMbtu. These positions
represent approximately 48 percent of its projected equity gas volumes in 2001.
Additionally, the Company has placed floors on approximately 10,000 barrels per
day of its equity production of crude, condensate and NGLs at a net equivalent
minimum oil price of $24.00 per barrel. This represents approximately 63 percent
of the Company's forecasted NGL production. All prices are NYMEX-equivalents.
For 2002, the Company has hedged approximately 40,000 MMbtus per day, or 27
percent of its projected equity gas production, with collar structures providing
for an average minimum price of $3.63 per MMbtu and an average maximum price of
$6.11 per MMbtu. These prices are NYMEX-equivalents. The Company has not hedged
any equity NGL volumes in 2002.
42
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
At December 31, 2000 the Company had $695,000 of gains unrecognized in inventory
that will be recognized primarily during the first quarter of 2001 which may be
partially offset by losses from the Company's related forward fixed price hedges
and physical sales. At December 31, 2000 the Company had unrecognized net losses
of $804,000 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.
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 or losses from such speculative activities for the years ended
December 31, 2000 and 1999 were not material.
Natural Gas Derivative Market Risk. As of December 31, 2000, the Company held a
notional quantity of approximately 291 Bcf of natural gas futures, swaps and
options extending from January 2000 to December 2001 with a weighted average
duration of approximately 4.4 months. This was comprised of approximately 116
Bcf of long positions and 175 Bcf of short positions in such instruments. As of
December 31, 1999, the Company held a notional quantity of approximately 202 Bcf
of natural gas futures, swaps and options extending from January 2000 to January
2001 with a weighted average duration of approximately three months. This was
comprised of approximately 87 Bcf of long positions and 115 Bcf of short
positions in such instruments.
Crude Oil and NGL Derivative Market Risk. As of December 31, 2000, the Company
held a notional quantity of approximately 156,240 MGal of NGL futures, swaps and
options extending from January 2000 to December 2001 with a weighted average
duration of approximately 6.5 months. This was comprised of approximately
156,240 MGal of long positions in such instruments. As of December 31, 1999, the
Company held a notional quantity of approximately 123,500 MGal of NGL futures,
swaps and options extending from January 2000 to December 2000 with a weighted
average duration of approximately seven months. This was comprised of
approximately 110,000 MGal of long positions and 12,000 MGal of short positions
in such instruments.
As of December 31, 2000, the Company had purchased puts for 125,000 barrels per
month of NYMEX monthly average settlement of $23.96 per barrel to hedge a
portion of the Company's equity production of natural gasoline, condensates,
butanes and crude oil. The Company held no crude oil futures, swaps or options
for settlement beyond 2001.
As of December 31, 2000, the Company had purchased puts for 125,000 barrels per
month of OPIS Mt. Belvieu monthly average settlement of $.434 per gallon to
hedge a portion of the Company's equity production of propane for 2001.
As of December 31, 2000, the Company had purchased puts for 60,000 barrels per
month of OPIS Mt. Belvieu monthly average settlement of $.3175 per gallon of
purity ethane puts to hedge a portion of the Company's equity production of
ethane for 2001.
As of December 31, 2000, the Company held no NGL futures, swaps or options for
settlement beyond 2001. As of December 31, 2000, the estimated fair value of the
aforementioned crude oil and NGL options held by the Company was approximately
$4.4 million.
Foreign Currency Derivative Market Risk. As part of its normal business, the
Company enters into physical gas transactions payable in Canadian dollars. The
Company enters into forward purchases and sales of Canadian dollars from time to
time to fix the cost of its future Canadian dollar denominated natural gas
purchase, sale, 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 the commitment for the payment obligation is made and the
actual payment date of such obligation. As of December 31, 2000, the net
notional value of such contracts was approximately $17.9 million in Canadian
dollars, which approximates its fair market value. As of December 31, 1999, the
net notional value of such contracts was approximately $7.5 million in Canadian
dollars, which approximated its fair market value.
43
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,
-----------------------------
2000 1999
----------- ------------
Master Shelf and Senior Notes............................ $ 305,000 $ 332,000
Variable Rate Revolving Credit Facility.................. 53,700 46,250
---------- -----------
Total long-term debt................................... $ 358,700 $ 378,250
========== ==========
Revolving Credit Facility. The Revolving Credit Facility is with a syndicate of
banks and provides for a maximum borrowing commitment of $250 million consisting
of an $83 million 364-day Revolving Credit Facility, or Tranche A, and a
five-year $167 million Revolving Credit Facility, or Tranche B. At December 31,
2000, $53.7 million in total was outstanding on this facility. The Revolving
Credit Facility bears interest at certain spreads over the Eurodollar rate, or
the greater of the Federal Funds rate or 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 and range
from .75% to 2.00%. At December 31, 2000, the interest rate payable on the
facility was 8.2%. The Company is required to maintain a total debt to
capitalization ratio of not more than 60% through December 31, 2000 and of not
more than 55% thereafter, and a senior debt to capitalization ratio of not more
than 40% through December 31, 2001 and of not more than 35% thereafter. The
agreement also requires a quarterly test of the ratio of EBITDA (excluding some
non-recurring items) for the last four quarters, to interest and dividends on
preferred stock for the same period. The ratio must exceed 1.80 to 1.0 through
September 30, 2001 and increases periodically to 3.25 to 1.0 by December 31,
2002. This facility is guaranteed by and secured via a pledge of the stock of
the Company's significant subsidiaries. The Company generally utilizes excess
daily funds to reduce any outstanding balances on the Revolving Credit Facility
and associated interest expense.
Master Shelf Agreement. In December 1991, the Company entered into a Master
Shelf Agreement with The Prudential Insurance Company of America. Amounts
outstanding under the Master Shelf Agreement at December 31, 2000 are as
indicated in the following table (000s):
Interest Final
Issue Date Amount Rate Maturity Principal Payments Due
- --------------------- ---------- ----------- ----------------- ------------------------------------------------
October 27, 1992 $ 25,000 7.99% October 27, 2003 $8,333 on each of October 27, 2001 through 2003
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
----------
$150,000
==========
In 1999, the Company amended its agreement with Prudential to reflect the
following provisions. The Company is required to maintain a current ratio, as
defined therein, of at least .9 to 1.0, a minimum tangible net worth equal to
the sum of $300 million plus 50% of consolidated net earnings earned from
January 1, 1999 plus 75% of the net proceeds of any equity offerings after
44
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
January 1, 1999, a total debt to capitalization ratio of not more than 60%
through December 31, 2001 and of not more than 55% thereafter and a senior debt
to capitalization ratio of not more than 40% through March 2002 and not more
than 35% thereafter. This agreement also requires an EBITDA to interest ratio of
not less than 2.50 to 1.0 increasing to a ratio of not less than 3.75 to 1.0 by
March 31, 2002 and an EBITDA to interest on senior debt ratio of not less than
4.00 to 1.0 increasing to a ratio of not less than 5.50 to 1.0 by March 31,
2002. EBITDA in these calculations excludes certain non-recurring items. In
addition, this agreement contains a calculation limiting dividends under which
approximately $64.1 million was available at December 31, 2000. The Company is
currently paying an annual fee of 0.50% on the amounts outstanding on the Master
Shelf Agreement. This fee will continue until the Company receives an implied
investment grade rating on its senior secured debt. Borrowings under the Master
Shelf Agreement are guaranteed by and secured via a pledge of the stock of
certain of the Company's significant subsidiaries.
1995 Senior Notes. In 1995, the Company sold $42.0 million of Senior Notes, the
1995 Senior Notes, to a group of insurance companies with an interest rate of
8.16% per annum. In March 1999, the Company prepaid $15.0 million of the
principal amount outstanding on the 1995 Senior Notes at par. The remaining
principal amount outstanding of $27.0 million was prepaid in September 2000 with
funds available under the Revolving Credit Facility. In connection with the
prepayment in 2000, the Company paid a pre-tax make-whole payment of
approximately $2.0 million and expensed capitalized fees of approximately
$752,000. The combined costs of approximately $2.7 million, net of a tax benefit
of $997,000, are reflected as an extraordinary charge on early extinguishment of
debt in the year ended December 31, 2000.
Senior Subordinated Notes. In 1999, the Company sold $155.0 million of Senior
Subordinated Notes in a private placement with a final maturity of 2009 due in a
single payment which were exchanged for registered publicly tradable notes under
the same terms and conditions. The Subordinated Notes bear interest at 10% and
were priced at 99.225% to yield 10.125%. These notes contain maintenance
covenants which include limitations on debt incurrence, restricted payments,
liens and sales of assets. The Subordinated Notes are unsecured and are
guaranteed on a subordinated basis by certain of its subsidiaries. The Company
incurred approximately $5.0 million in offering commissions and expenses which
have been capitalized and will be amortized over the term of the notes.
Covenant Compliance. The Company was in compliance with all covenants in its
debt agreements at December 31, 2000. Taking into account all the covenants
contained in these agreements, the Company had approximately $156 million of
available borrowing capacity at December 31, 2000.
Approximate future maturities of long-term debt in the year indicated are as
follows at December 31, 2000 (000s):
2001............................................................... $ 33,333
2002............................................................... 8,333
2003............................................................... 43,334
2004............................................................... 88,700
2005............................................................... 10,000
Thereafter......................................................... 175,000
----------
Total................................................ $ 358,700
==========
The Company intends to use funds available under its Revolving Credit Facility
to finance the 2001 maturities.
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.
45
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
December 31, 2000 December 31, 1999
--------------------------- ---------------------------
Carrying Fair Carrying Fair
Value Value Value Value
------------ --------- ------------ ----------
(000s) (000s)
Cash and cash equivalents............................ $ 12,927 $ 12,927 $ 14,062 $ 14,062
Trade accounts receivable............................ 546,791 546,791 210,628 210,628
Accounts payable..................................... 587,822 587,822 240,235 240,235
Long-term debt....................................... 358,700 359,011 378,250 367,496
Risk management contracts............................ $ - $ 5,107 $ - $ (1,668)
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. Fair market value for this debt 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 this 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, 2000,
1999 and 1998, excluding the tax effect of the extraordinary items, is comprised
of (000s):
2000 1999 1998
---------- ---------- ----------
Current:
Federal................................................. $ 250 $ 2,261 $ (5,696)
State................................................... 600 - -
--------- --------- --------
Total Current........................................... 850 2,261 (5,696)
--------- --------- ---------
Deferred:
Federal................................................. 31,497 (11,004) (31,272)
State................................................... 1,215 (424) (1,450)
--------- --------- ---------
Total Deferred.......................................... 32,712 (11,428) (32,722)
--------- --------- ---------
Total tax provision (benefit).................. $ 33,562 $ (9,167) $ (38,418)
========= ========= =========
The tax benefit allocated to the extraordinary charges were $997,000 and
$628,000 for the years ended December 31, 2000 and 1999, respectively.
Temporary differences and carry-forwards which give rise to the deferred tax
liabilities (assets) at December 31, 2000 and 1999, net of the tax effect of the
extraordinary items, are as follows (000s):
46
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
2000 1999
---------- ----------
Property and equipment......................................................... $ 137,042 $ 108,357
Differences between the book and tax basis of acquired assets.................. 12,509 13,439
---------- ----------
Total deferred income tax liabilities...................................... 149,551 121,796
---------- ----------
Alternative Minimum Tax ("AMT") credit carry-forwards.......................... (23,640) (23,389)
Net Operating Loss ("NOL") carry-forwards...................................... (58,231) (62,442)
---------- ----------
Total deferred income tax assets........................................... (81,871) (85,831)
---------- ----------
Net deferred income taxes.................................................. $ 67,680 $ 35,965
========== ==========
The differences between the provision (benefit) for income taxes at the
statutory rate and the actual provision (benefit) for income taxes, before the
tax effect of extraordinary items, for the years ended December 31, 2000, 1999
and 1998 are summarized as follows (000s):
2000 % 1999 % 1998 %
---------- ------ --------- ------ -------- -------
Income tax (benefit) before effect of extraordinary
item at statutory rate...................... $ 31,984 35.0 $ (8,814) 35.0 $(36,968) 35.0
State income taxes (benefit), net of federal
benefit...................................... 1,280 1.4 (353) 1.4 (1,450) 1.4
Other............................................ 298 .3 - - - -
---------- ----------- --------- -------- -------- --------
Total........................................ $ 33,562 36.7 $ (9,167) 36.4 $(38,418) 36.4
========== ======== ========= ======== ======== =======
At December 31, 2000, the Company had NOL carry-forwards for federal and state
income tax purposes and AMT credit carry-forwards for federal income tax
purposes of approximately $160.0 million and $23.6 million, respectively. These
carry-forwards expire as follows (000s):
Expiration Dates NOL AMT
---------------- ----------- -----------
2007 .......................... $ 297 $ -
2008 .......................... 11,269 -
2009 .......................... - -
2010 .......................... 45,140 -
2011 .......................... 15,247 -
2012 .......................... 39,210 -
2018 .......................... 48,833 -
No expiration.................. - 23,640
----------- -----------
Total..................... $ 159,996 $ 23,640
=========== ===========
The Company believes that the NOL carry-forwards and AMT credit carry-forwards
will be utilized prior to their expiration because they are substantially offset
by existing taxable temporary differences reversing within the carry-forward
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.
47
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 8 - COMMITMENTS AND CONTINGENT LIABILITIES
- -----------------------------------------------
Western Gas Resources, Inc., Mountain Gas Resources, Inc., v. R.I.S. Resources
International Corporation, a British Columbia , Canada corporation; RIS
Resources (USA) Inc., a Texas Corporation, United States District Court,
Colorado, Civil Action No. 00-S-599. The Company's wholly-owned subsidiary,
Mountain Gas, was a defendant in prior litigation, styled as McMurry Oil
Company, et al. v. TBI Exploration, Inc., Mountain Gas Resources, Inc. and
Wildhorse Energy Partners, LLC, District Court, Ninth Judicial District,
Sublette County, Wyoming, Civil Action No. 5882, which was settled in 2000, on
all issues, for substantially less than the amount claimed. The Company and
Mountain Gas are seeking reimbursement from RIS Resources, (USA), Inc., Mountain
Gas' joint venture partner, for 50% of the settlement amount which was paid in
full by Mountain Gas. On January 16, 2001, RIS filed its answer to Mountain Gas'
complaint along with a counterclaim alleging slander of title and intentional
interference with prospective business advantage seeking an unspecified amount
of damages, including punitive damages and other relief. While the Company
believes the counterclaim is without merit and intends to vigorously contest the
allegations, it cannot predict the outcome of this matter with any certainty.
The parties are proceeding with discovery.
.
Western Gas Resources, Inc., v. Amerada Hess Corporation, District Court, Denver
County, Colorado, Civil Action No. 00-CV-1433. The Company was a defendant in
prior litigation, styled as Berco Resources, Inc. v. Amerada Hess Corporation
and Western Gas Resources, Inc., United States District Court, District of
Colorado, Civil Action No. 97-WM-1332, which was settled in 2000 for an amount
which did not have a material impact on the Company's results of operations or
financial position. The Company is seeking reimbursement from Amerada Hess under
a contractual indemnity. Amerada Hess sought a motion to dismiss, which was
denied. The Company has amended its original complaint and requested a jury
trial in this case. The parties are proceeding with discovery.
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 its financial
position or results of operations.
NOTE 9 - BUSINESS SEGMENTS AND RELATED INFORMATION
- --------------------------------------------------
The Company operates in four principal business segments, as follows: Gas
Gathering and Processing, Production, Marketing and Transportation, and these
segments are separately monitored by management for performance against its
internal forecast and are consistent with the Company's internal financial
reporting package. These segments have been identified based upon the differing
products and services, regulatory environment and the expertise required for
these operations.
The Gas Gathering and Processing segment connects producers' wells to the
Company's gathering systems for delivery to its processing or treating plants,
processes the natural gas to extract NGLs and treats the natural gas in order to
meet pipeline specifications. The results of the Company's Black Lake facility
and related reserves, which were sold in December 1999, are included in this
segment for the years ended December 31, 1999 and 1998. The residue gas and NGLs
extracted at the processing facilities are sold by the Marketing segment.
The activities of the Production segment include the exploration and development
of gas properties primarily in basins where the Company's gathering and
processing facilities are located. The majority of the production from these
properties is sold by the Marketing segment.
The Company's Marketing segment buys and sells gas and NGLs nationwide and in
Canada from or to a variety of customers. In addition, this segment also markets
gas and NGLs produced by the Company's gathering, processing and production
assets.
48
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The operations associated with the Katy Facility, which was sold in April 1999,
are included in the Marketing segment for the years ended December 31, 1999 and
1998. Also included in this segment are the Company's Canadian marketing
operations (which are immaterial for separate presentation). The Marketing
segment also includes losses associated with the Company's equity gas and NGL
hedging program of $(38.9) million, $(10.9) million and $7.5 million for the
years ended December 31, 2000, 1999 and 1998, respectively.
The Transportation segment reflects the operations of the Company's MIGC and
MGTC pipelines. The majority of the revenue presented in this segment is derived
from transportation of residue gas.
The following table sets forth the Company's segment information as of and for
the years ended December 31, 2000, 1999 and 1998 (in 000s). Due to the Company's
integrated operations, the use of allocations in the determination of business
segment information is necessary. Inter-segment revenues are valued at prices
comparable to those of unaffiliated customers.
Gas
Gathering Elim-
and Producing Trans- inating
Processing Properties Marketing mission Corporate Entries Total
----------- ---------- ---------- --------- --------- ------------- ---------
Year ended December 31, 2000
Revenues from unaffiliated
customers................................. $ 59,687 $ 865 $ 3,271,424 $ 8,619 $ 103 $ - $ 3,340,698
Interest income........................... 98 6 27 - 27,505 (26,987) 649
Other, net................................ 1,734 137 (63,226) - 1,957 39 (59,359)
Inter-segment sales....................... 813,802 87,558 94,858 16,484 44 (1,012,746) -
----------- --------- ----------- ---------- -------- ----------- -----------
Total revenues............................ 875,321 88,566 3,303,083 25,103 29,609 (1,039,694) 3,281,988
----------- --------- ----------- ---------- -------- ----------- -----------
Product purchases......................... 662,319 4,677 3,322,458 (1,021) (184) (1,002,748) 2,985,501
Plant operating expense................... 62,507 451 69 8,856 (264) (1,727) 69,892
Oil and gas exploration
and production expense.................... 32 28,613 - - - (9,124) 19,521
----------- --------- ----------- ---------- -------- ----------- -----------
Operating margin.......................... $ 150,463 $ 54,825 $ (19,444) $ 17,268 $ 30,057 $ (26,095) $ 207,074
=========== ========= =========== ========== ======== =========== ===========
Depreciation, depletion and
amortization.............................. 36,284 14,161 161 1,645 5,668 - 57,919
Interest expense.......................... 33,460
Impairment of property & plant............ -
Gain on sale of assets.................... (9,406)
Selling and administrative expense........ 33,717
-----------
Income before income taxes................ $ 91,384
===========
Identifiable assets....................... $ 537,729 $ 129,807 $ 55 $ 43,111 $ 42,441 $ - $ 753,143
=========== ========= =========== ========== ======== =========== ===========
49
Gas
Gathering Elim-
and Producing Trans- inating
Processing Properties Marketing mission Corporate Entries Total
----------- ---------- ---------- --------- --------- --------- ------
Year ended December 31, 1999
Revenues from unaffiliated
customers................................. $ 43,257 $ 2,895 $ 1,858,776 $ 7,498 $ 554 $ - $ 1,912,980
Interest income........................... 2 1 100 - 25,715 (25,435) 383
Other, net................................ 1,483 - (7,078) 413 2,543 - (2,639)
Inter-segment sales....................... 389,928 26,137 88,379 16,235 56 (520,735) -
----------- --------- ----------- ---------- -------- ---------- -----------
Total revenues............................ 434,670 29,033 1,940,177 24,146 28,868 (546,170) 1,910,724
----------- --------- ----------- ---------- -------- ---------- -----------
Product purchases......................... 288,668 2,029 1,939,400 - - (514,258) 1,715,839
Plant operating expense................... 62,301 68 1,718 11,237 (1,478) (6,427) 67,419
Oil and gas exploration
and production expense.................... 535 8,705 (44) - - - 9,196
----------- --------- ----------- ---------- -------- ---------- -----------
Operating margin.......................... $ 83,166 $ 18,231 $ (897) $ 12,909 $ 30,346 $ (25,485) $ 118,270
=========== ========= ============ ========== ======== ========== ===========
Depreciation, depletion and
amortization.............................. 35,763 8,181 1,226 1,166 4,645 - 50,981
Interest expense.......................... 33,156
Impairment of property & plant............ 1,158
Loss on sale of assets.................... 29,802
Selling and administrative expense........ 28,357
-----------
Loss before income taxes.................. $ (25,184)
===========
Identifiable assets....................... $ 606,424 $ 104,470 $ 73 $ 70,354 $ 18,837 $ - $ 800,158
=========== ========= =========== ========== ======== ========== ===========
Gas
Gathering Elim-
and Producing Trans- inating
Processing Properties Marketing mission Corporate Entries Total
----------- ---------- ---------- --------- --------- --------- ------
Year ended December 31, 1998
Revenues from unaffiliated
customers........................... $ 37,171 $ 2,089 $ 2,060,685 $ 4,952 $ 247 $ - $ 2,105,144
Interest income..................... 1 - 174 - 29,402 (28,486) 1,091
Other, net.......................... (4,554) 703 13,086 659 959 - 10,853
Inter-segment sales................. 431,511 18,263 81,473 12,365 232 (543,844) -
----------- --------- ----------- ---------- --------- ---------- -----------
Total revenues...................... 464,129 21,055 2,155,418 17,976 30,840 (572,330) 2,117,088
----------- --------- ----------- ---------- --------- ---------- -----------
Product purchases................... 325,414 1,431 2,127,907 82 - (540,531) 1,914,303
Plant operating expense............. 73,724 36 7,460 9,944 (2,412) (3,399) 85,353
Oil and gas exploration
and production expense.............. 535 7,162 155 - 3 141 7,996
----------- --------- ----------- ---------- --------- ---------- -----------
Operating margin.................... $ 64,456 $ 12,426 $ 19,896 $ 7,950 $ 33,249 $ (28,541) $ 109,436
=========== ========= =========== ========== ========= ========== ===========
Depreciation, depletion and
amortization........................ 40,679 8,831 4,000 1,013 4,823 - 59,346
Interest expense.................... 33,616
Impairment of property & plant ..... 108,447
50
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Gain) on sale of assets ........... (16,478)
Selling and administrative expense.. 30,128
-----------
Loss before income taxes............ $ (105,623)
===========
Identifiable assets................. $ 577,782 $ 89,191 $ 118,661 $ 63,946 $ 17,780 $ - $ 867,360
=========== ========= =========== ========== ========= ========== ===========
NOTE 10 - EMPLOYEE BENEFIT PLANS
- --------------------------------
Retirement Plan. A discretionary retirement 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 and, in 2000, provided for a match of 50% of employee
contributions on the first 4% of employee compensation contributed. Effective
January 2001, the match of employee contributions has been increased to a
sliding scale of 60% to 100% of the first 5% of employee compensation based upon
years of service. Contributions are made to mutual funds and to purchase Company
stock for which Fidelity Management Trust Company acts as trustee. The
discretionary contributions made by the Company were $2.3 million, $1.7 million
and $1.9 million, for the years ended December 31, 2000, 1999 and 1998,
respectively. The matching contributions were approximately $470,000, $541,000
and $668,000 for the years ended December 31, 2000, 1999 and 1998, respectively.
Key Employees' Incentive Stock Option Plan and 1987 Non-Employee Directors 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 ("1987 Directors Plan") that authorized the
granting of options to purchase 250,000 and 20,000 shares of the Company's
Common Stock, respectively. Each of these plans have terminated. The Company
loaned to certain employees, an amount sufficient to exercise their options
under these plans. The loan and accrued interest will be forgiven if the
employee is continually employed by the Company and upon a resolution of the
board of directors. As of December 31, 2000 and 1999, loans related to 75,000
shares of Common Stock totaling $803,000 were outstanding under these terms.
1999 Non-Employee Directors Stock Option Plan. Effective March 1999, the board
of directors of the Company adopted a 1999 Non-Employee Directors' Stock Option
Plan ("1999 Directors Plan") that authorized the granting of options to purchase
15,000 shares of the Company's Common Stock. During 1999, the board approved
grants totaling 15,000 options to several board members. Under this plan, each
of these options becomes exercisable as to 33 1/3% of the shares covered by it
on each anniversary from the date of grant. This plan terminates on the earlier
of March 12, 2009 or the date on which all options granted under the plans have
been exercised in full.
1993, 1997 and 1999 Stock Option Plans. The 1993 Stock Option Plan ("1993
Plan"), the 1997 Stock Option Plan ("1997 Plan"), and the 1999 Stock Option Plan
("1999 Plan") became effective on March 29, 1993, May 21, 1997, and May 21,
1999, respectively, 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 and 750,000 shares of Common Stock
for issuance upon exercise of options under the 1999 Plan. The 1993 Plan, the
1997 Plan and the 1999 Plan will terminate on the earlier of March 29, 2003, May
21, 2007 and May 21, 2009, respectively, or the date on which all options
granted under each of the plans have been exercised in full.
Under each 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 re-issuance
pursuant to a new option. The board of directors has the right to, among other
things, fix the method by which the price is determined and the terms and
conditions for the grant or exercise of any option. The purchase price of the
stock under each option shall be the average closing price for the ten days
prior to the grant. Under the 1993 Plan, options granted vest 20% each year on
the anniversary of the date of grant. Under the
51
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1997 and 1999 Plans, the board of directors has the authority to set the vesting
schedule from 20% per year to 33 1/3% per year. Under each of the plans, the
employee must exercise the option within five years of the date each portion
vests.
In March 1999, certain officers of the Company were granted a total of 300,000
options, which vest ratably over the next three years, under the 1997 Plan. The
exercise price of $5.51 per share was determined by using the average stock
price for the ten trading days prior to the grant date. In exchange, these
officers were required to relinquish a total of 246,200 vested and unvested
options at prices ranging from $18.63 to $34.00 per share.
The following table summarizes the number of stock options exercisable and
available for grant under the Company's benefit plans:
Per Share Key 1987 1999
Price Employee Directors Directors
Range Plan Plan Plan 1993 Plan 1997 Plan 1999 Plan
----- ---- ---- ---- --------- --------- ---------
Exercisable:
December 31, 2000............ 4.59-19.65 - - 1,683 389,806 131,431 11,255
December 31, 1999............ 4.59-18.63 - - - 407,787 47,240 -
December 31, 1998............ 10.71-32.38 75,000 13,500 - 562,138 26,250 -
Available for Grant:
December 31, 2000............ - - - - - - 608,934
December 31, 1999............ - - - - - - 714,734
December 31, 1998............ - 31,250 1,250 - 96,609 763,400 -
The following table summarizes the stock option activity under the Company's
benefit plans:
Per Share Key 1987 1999
Price Employee Directors Directors
Range Plan Plan Plan 1993 Plan 1997 Plan 1999 Plan
----- ---- ---- ---- --------- --------- ---------
Balance 12/31/97 ....... 75,000 13,500 - 983,330 171,100 -
Granted ............. $ 19.28 - - - 40,511 106,500 -
Exercised ........... $ 15.83 - - - (1,556) - -
Forfeited or canceled $19.19-21.78 - - - (129,809) (41,000) -
Balance 12/31/98 ....... 75,000 13,500 - 892,476 236,600 -
Granted ............. $ 4.59-17.11 - - 15,000 - 505,500 35,266
Exercised ........... $10.71-16.50 - (8,500) - (1,938) (3,300) -
Forfeited or canceled $ 4.59-35.50 (75,000) (5,000) - (324,664) (92,100) -
Balance 12/31/99 ....... - - 15,000 565,874 646,700 35,266
Granted ............. $12.58-23.45 - - - - - 115,300
Exercised ........... $ 4.59-20.69 - - (3,317) (59,261) (136,722) (100)
Forfeited or canceled $ 4.59-35.00 - - - (38,592) (8,601) (9,500)
Balance 12/31/00 ....... - - 11,683 468,021 501,377 140,966
The following table summarizes the weighted average option exercise price
information under the Company's benefit plans:
Key 1987 1999
Employee Directors Directors
Plan Plan Plan 1993 Plan 1997 Plan 1999 Plan
---- ---- ---- --------- --------- ---------
Balance 12/31/97................... $ 30.23 $ 14.13 $ - $ 20.93 $ 19.63 $ -
Granted......................... - - - 19.28 11.69 -
52
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Excercised...................... - - - (14.78) - -
Forfeited or canceled........... - - - (21.97) (19.16) -
--------- --------- -------- --------- ----------- ---------
Balance 12/31/98................... 30.23 14.13 - 20.71 16.15 -
Granted......................... - - 5.51 - 5.15 13.58
Excercised...................... - (10.71) - (14.53) (11.64) -
Forfeited or canceled........... (30.23) (19.94) - (22.79) (15.11) -
--------- --------- -------- --------- ----------- ---------
Balance 12/31/99................... - - 5.51 19.54 7.72 13.58
Granted......................... - - - - - 23.11
Excercised................... - - (5.51) (16.17) (7.33) (16.21)
Forfeited or canceled........... - - - (26.97) (8.66) (22.25)
--------- --------- -------- --------- ----------- ---------
Balance 12/31/00................... $ - $ - $ 5.51 $ 19.35 $ 7.81 $ 20.79
========= ========= ======== ========= =========== =========
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 that a statement of operations is presented. Such information was only
calculated for the options granted under the 1993 Plan, the 1997 Plan, the 1999
Plan, and the 1999 Directors' Plan, as there were no grants under any other
plans. The weighted average fair value of options granted under the 1997 Plan
was $9.56 and $1.00 for the years ended December 31, 1999 and 1998,
respectively. There were no grants under the 1997 Plan during the year ended
December 31, 2000. The weighted average fair value of options granted under the
1999 Plan was $21.20 and $6.82 for the years ended December 31, 2000 and 1999,
respectively. The weighted average fair value of options granted under the 1999
Directors' Plan was $9.12 for the year ended December 31, 1999. The weighted
average fair value of options granted was estimated using the Black-Scholes
option-pricing model with the following assumptions:
1999
Directors'
1999 Plan 1997 Plan Plan
--------- --------- ----
1999 2000 1999 1998 1999
---- ---- ---- ---- ----
Risk-free interest rate....................... 6.96% 5.95% 6.96% 5.3% 6.96%
Expected life (in years)...................... 5 5 5 6 5
Expected volatility........................... 51% 54% 51% 45% 51%
Expected dividends (quarterly)................ $ .05 $ .05 $ .05 $ .05 $ .05
Had compensation expense for the Company's 2000, 1999 and 1998 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):
2000 1999 1998
--------------------------- --------------------------- ---------------------------
As Reported Pro forma As Reported Pro forma As Reported Pro forma
------------- ----------- ------------- ----------- ------------- -----------
Net income (loss)...................... $ 56,108 $ 54,374 $ (17,124) $ (18,589) $ (67,205) $ (67,997)
Net income (loss) attributable to
common stock ....................... 45,692 43,958 (27,563) (29,028) (77,644) (78,436)
Earnings (loss) per share of common
stock .............................. 1.42 1.36 (.86) (.90) (2.42) (2.44)
Earnings (loss) per share of common
stock - assuming dilution.......... $ 1.39 $ 1.34 $ (.86) $ (.90) $ (2.42) $ (2.44)
53
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The fair market value of the options at grant date is amortized over the
appropriate vesting period for purposes of calculating compensation expense.
NOTE 11 - SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
- ----------------------------------------------------------------------
(UNAUDITED):
- ------------
Costs. The following tables set forth capitalized costs at December 31, 2000,
1999 and 1998 and costs incurred for oil and gas producing activities for the
years ended December 31, 2000, 1999 and 1998 (000s):
2000 1999 1998
----------- ------------ ------------
Capitalized costs:
Proved properties...................................................... $ 119,124 $ 74,594 $ 110,090
Unproved properties.................................................... 46,890 42,928 33,255
---------- ---------- ----------
Total...................................................................... 166,014 117,522 143,345
Less accumulated depletion............................................. (36,367) (23,003) (58,994)
---------- ---------- ----------
Net capitalized costs...................................................... $ 129,647 $ 94,519 $ 84,351
========== ========== ==========
Costs incurred:
Acquisition of properties
Proved................................................................. $ - $ - $ 2,174
Unproved............................................................... 8,774 11,675 22,633
Development costs.......................................................... 35,807 20,973 23,208
Exploration costs.......................................................... 8,397 5,148 4,177
---------- ---------- ----------
Total costs incurred....................................................... $ 52,978 $ 37,796 $ 52,192
========== ========== ==========
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, 2000, 1999 and 1998 are as follows (000s):
2000 1999 1998
---------- ----------- ------------
Revenues from sale of oil and gas:
Sales.................................................................. $ 4,658 $ 2,081 $ 2,592
Transfers.............................................................. 80,353 30,537 23,188
---------- ---------- ----------
Total............................................................... 85,011 32,618 25,780
Production costs........................................................... (27,108) (8,002) (6,611)
Exploration costs.......................................................... (2,213) (1,492) (1,599)
Depreciation, depletion and amortization................................... (13,423) (11,536) (11,749)
Impairment of oil and gas properties....................................... - - (16,528)
Income tax benefit (expense)............................................... (14,793) (3,921) 3,690
---------- ---------- ----------
Results of operations...................................................... $ 27,474 $ 7,667 $ (7,017)
========== ========== ==========
54
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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.
The following table sets forth information for the years ended December 31,
2000, 1999 and 1998 with respect to changes in the Company's proved developed
and undeveloped reserves, all of which are in the United States.
Natural Crude
Gas Oil
(MMcf) (MBbls)
-------- ---------
Proved reserves:
December 31, 1997................................................................. 212,596 806
Revisions of previous estimates................................................... 28,617 (200)
Extensions and discoveries........................................................ 43,248 66
(Sales) Purchases of reserves in place, net....................................... (31,020) -
Production........................................................................ (14,511) (117)
-------- ---------
December 31, 1998................................................................. 238,930 555
Revisions of previous estimates................................................... 13,152 (2)
Extensions and discoveries........................................................ 45,688 14
(Sales) Purchases of reserves in place............................................ (7,964) (126)
Production........................................................................ (17,988) (112)
-------- ---------
December 31, 1999................................................................. 271,818 329
Revisions of previous estimates................................................... (11,889) (194)
Extensions and discoveries........................................................ 176,584 332
(Sales) Purchases of reserves in place............................................ - -
Production........................................................................ (28,019) (28)
-------- ---------
December 31, 2000................................................................. 408,494 439
======== =========
Proved developed reserves, included above:
December 31, 1997................................................................. 102,363 490
December 31, 1998................................................................. 65,733 393
December 31, 1999................................................................. 106,626 161
December 31, 2000................................................................. 208,218 147
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.
55
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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.
The assumptions used to compute estimated future cash inflows 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 unexpected delays in development, changes in prices or
regulatory or environmental policies. 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.
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 pre-tax 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, 2000, 1999 and
1998 is as follows (000s):
2000 1999 1998
---------- ----------- ----------
Future cash inflows.......................................................... $2,682,435 $ 419,104 $ 345,217
Future production costs...................................................... (462,065) (121,129) (108,457)
Future development costs..................................................... (87,251) (57,999) (46,066)
Future income tax expense.................................................... (732,327) (67,429) (48,894)
---------- ---------- ----------
Future net cash flows........................................................ 1,400,792 172,547 141,800
10% annual discount for estimated timing of cash flows....................... (432,881) (59,620) (43,923)
---------- ---------- ----------
Standardized measure of discounted future net cash flows relating to
proved oil and gas reserves............................................. $ 967,911 $ 112,927 $ 97,877
========== ========== ==========
56
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Principal changes in the Company's estimated discounted future net cash flows
for the years ended December 31, 2000, 1999 and 1998 are as follows (000s):
2000 1999 1998
---------- ----------- ----------
January 1....................................................................... $ 112,927 $ 97,877 $ 99,573
Sales and transfers of oil and gas produced, net of production costs......... (67,024) (24,616) (19,170)
Net changes in prices and production costs related to future production...... 768,840 19,569 367
Development costs incurred during the period................................. 35,807 20,973 23,208
Changes in estimated future development costs................................ (21,369) (29,725) (33,723)
Changes in extensions and discoveries........................................ 640,501 26,257 23,336
Revisions of previous quantity estimates..................................... (55,589) 5,653 30,452
Purchases (sales) of reserves in place....................................... - (5,842) (38,251)
Accretion of discount........................................................ 15,706 13,162 13,219
Net change in income taxes................................................... (461,888) (10,381) (1,134)
---------- ---------- ----------
December 31..................................................................... $ 967,911 $ 112,927 $ 97,877
========== ========== ==========
NOTE 12 - 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
--------- ---------- --------- --------------- ---------------
2000 quarter ended:
March 31...................... $ 565,152 $ 36,591 $ 13,006 $ .32 $ .32
June 30....................... 641,816 32,310 10,580 .25 .24
September 30.................. 909,836 42,618 14,457 .37 .36
December 31................... 1,165,184 47,042 18,065 .48 .47
------------ ---------- --------- ------------ ----------
$ 3,281,988 $ 158,561 $ 56,108 $ 1.42 $ 1.39
============ ========== ========= ============ ==========
1999 quarter ended:
March 31...................... $ 429,360 $ 13,259 $ (2,176) $ (.15) $ (.15)
June 30....................... 456,302 (6,449) (14,764) (.54) (.54)
September 30.................. 505,550 16,794 1,058 (.05) (.05)
December 31................... 519,512 13,883 (1,242) (b) (.12) (.12)
------------ ---------- --------- ------------ ----------
$ 1,910,724 $ 37,487 $ (17,124) $ (.86) $ (.86)
============ ========== ========= ============ ==========
(a) Excludes selling and administrative, interest and income tax expenses, loss
on the impairment of property and equipment and extraordinary charges for
early extinguishment of debt.
(b) Includes a pre-tax, non-cash expense resulting from the evaluation of
property and equipment in accordance with SFAS No. 121 of $1.2 million.
57
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 Proxy Statement to be so filed
for the Company's annual meeting of stockholders scheduled for May 18, 2001 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 29 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 Amended and Restated Bylaws of Western Gas Resources, Inc. adopted by
the Board of Directors on February 12, 1999. (Filed as exhibit 12.1 to Western
Gas Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended
December 31, 1999 and incorporated herein by reference).
4.1 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).
4.2 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).
58
4.3 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).
4.4 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).
4.5 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).
4.6 Indenture between Western Gas Resources, Inc. and Guarantors to Chase
Bank of Texas, National Association, Trustee for $225,000,000 Senior
Subordinated Notes Due 2009, dated June 15, 1999. (Filed as exhibit 28 to
Western Gas Resources, Inc.'s Form 10-Q for the three months ended June 30, 1999
and incorporated herein by reference).
4.7 Western Gas Resources, Inc., 1999 Stock Option Plan. (Filed as an
exhibit to Western Gas Resources Inc.'s Registration Statement on Form S-8,
Registration No. 33-95255 dated January 24, 2000 and incorporated herein by
reference).
4.8 Western Gas Resources, Inc., Non-Employee Director Stock Option Plan.
(Filed as an exhibit to Western Gas Resources Inc.'s Registration Statement on
Form S-8, Registration No. 33-95259 dated January 24, 2000 and incorporated
herein by reference).
4.9 Western Gas Resources, Inc., Exchange Offer. (Filed as an exhibit to
Western Gas Resources Inc.'s Registration Statement on Form S-3, Registration
No. 33-86881 dated April 19, 1999 and incorporated herein by reference).
4.10 Western Gas Resources, Inc. First Supplemental Indenture to 10% Senior
Subordinated Notes due 2009 dated October 19, 1999.
4.11 Western Gas Resources, Inc. Second Supplemental Indenture to 10%
Senior Subordinated Notes due 2009 dated September 29, 2000.
4.12 Western Gas Resources, Inc. Third Supplemental Indenture to 10% Senior
Subordinated Notes due 2009 dated January 3, 2001.
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 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).
10.3 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).
10.4 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).
10.5 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).
59
10.6 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).
10.7 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).
10.8 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).
10.9 Amended and Restated Note Purchase Agreement dated April 28, 1999 by
and among Western Gas Resources, Inc. and the Purchasers identified therein.
(Filed as exhibit 10.21 to Western Gas Resources, Inc.'s Form 10-Q for the three
months ended March 31, 1999 and incorporated herein by reference).
10.10 Offer to Acquire Notes dated February 12, 1999 by and between Western
Gas Resources, Inc. and CIGNA Investments, Inc., Royal Maccabees Life Insurance
Company, The Canada Life Assurance Company, and Canada Life Insurance Company of
America, original Purchasers under the Note Purchase Agreement dated as of April
1, 1993 by and between Company and Purchasers for $50,000,000, 7.65% Senior
Notes due April 30, 2003. (Filed as exhibit 12.3 in Western Gas Resources, Inc.
Form 10-K for the year ended December 31, 1998 and incorporated herein by
reference).
10.11 Offer to Acquire Notes dated February 12, 1999 by and between Western
Gas Resources, Inc. and MONY Life Insurance Company, one of the original
Purchasers under the Note Purchase Agreement dated as of November 29, 1995 by
and between Company and Purchasers for $42,000,000, 8.02% Senior Notes due
December 1, 2005. (Filed as exhibit 12.4 in Western Gas Resources, Inc. Form
10-K for the year ended December 31, 1998 and incorporated herein by reference).
10.12 Letter Amendment No. 2 dated March 31, 1999 to the Second Amended and
Restated Master Shelf Agreement effective January 31, 1996 by and among Western
Gas Resources, Inc. and The Prudential Insurance Company of America and Pruco
Life Insurance Company. (Filed as exhibit 10.22 in Western Gas Resources, Inc.
Form 10-Q for the three months ended March 31, 1999 and incorporated herein by
reference).
10.13 Loan Agreement dated April 29, 1999 by and among Western Gas
Resources, Inc. and NationsBank, as agent, and the Lenders. (Filed as exhibit
10.20 in Western Gas Resources, Inc. Form 10-Q for the three months ended March
31, 1999 and incorporated herein by reference).
10.14 Letter Amendment No. 3 dated June 1, 1999 to the Second Amended and
Restated Master Shelf Agreement effective January 31, 1996 by and among Western
Gas Resources, Inc. and The Prudential Insurance Company of America and Pruco
Life Insurance Company.
10.15 First Amendment dated June 10, 1999 to Loan Agreement dated April 29,
1999 by and among Western Gas Resources, Inc. and NationsBank as Agent, and the
Lenders.
10.16 Third Amendment dated April 27, 2000 to Loan Agreement dated April
29, 1999 by and among Western Gas Resources, Inc. and NationsBank, as agent, and
the Lenders. (Filed as exhibit 10.23 in Western Gas Resources, Inc. Form 10-Q
for the three months ended March 31, 2000 and incorporated herein by reference).
10.17 Limited Waiver, Consent, Release and Amendment No. 4 dated August 25,
2000 to the Second Amended and Restated Master Shelf Agreement effective January
31, 1996 by and among Western Gas Resources, Inc. and The Prudential Insurance
Company of America and Pruco Life Insurance Company. (Filed as exhibit 10.24 to
Western Gas Resources, Inc., Form 10-Q for the nine months ended September 30,
2000 and is incorporated herein by reference).
10.18 Fourth Amendment dated August 15, 2000 to Loan Agreement dated April
19, 1999, by and among Western Gas Resources, Inc. and NationsBank, as Agent,
and the Lenders. (Filed as exhibit 10.25 to Western Gas Resources, Inc., Form
10-Q for the nine months ended September 30, 2000 and is incorporated herein by
reference).
60
10.19 Fifth Amendment dated November 22, 2000 to Loan Agreement dated April
29, 1999 by and among Western Gas Resources, Inc. and NationsBank, as agent, and
the Lenders.
10.20 Limited Waiver, Consent, Release and Amendment No. 5 dated November
22, 2000 to the Second Amended and Restated Master Shelf Agreement by and among
Western Gas Resources, Inc. and The Prudential Insurance Company of America and
Pruco Life Insurance Company.
11.1 Statement regarding computation of per share earnings.
21.1 List of Subsidiaries of Western Gas Resources, Inc.
23.1 Consent of PricewaterhouseCoopers LLP
23.2 Consent of Netherland, Sewell & Associates, Inc.
27 Financial Data Schedule
(b) Reports on Form 8-K:
Western Gas Resources, Inc., filed a report on Form 8-K on January 2,
2000 announcing the sale of its interest in the Black Lake Facility
in Louisiana and financial information related thereto, which is
incorporated herein by reference.
A report on Form 8-K was filed on January 21, 2000 to notify our
stockholders of the disposition of the Black Lake facility and
related production, which is incorporated herein by reference.
Western Gas Resources, Inc., filed a report on Form 8-K on February
22, 2000 announcing the stock sale of its wholly-owned subsidiary
Western Gas Resources-California, Inc., and a report on the McMurry
Oil Company, et al., v. TBI Exploration, Inc., Mountain Gas
Resources, Inc., and Wildhorse Energy Partners, LLC, District Court,
Ninth Judicial District, Sublette County, Wyoming, Civil Action No.
5882, which is incorporated herein by reference.
(c) Exhibits required by Item 601 of Regulation S-K. See (a) (3) above.
61
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 14, 2001.
WESTERN GAS RESOURCES, INC.
---------------------------
(Registrant)
By: /S/ Lanny F. Outlaw
-------------------------
Lanny F. Outlaw
Chief Executive Officer, President and Director
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 March 15, 2001
- ------------------------------
Brion G. Wise
/S/ W. L. Stonehocker Vice Chairman of the Board March 15, 2001
- ------------------------------
Walter L. Stonehocker
/S/ B. M. Sanderson Director March 15, 2001
- ------------------------------
Bill M. Sanderson
/S/ Richard B. Robinson Director March 15, 2001
- ------------------------------
Richard B. Robinson
/S/ Dean Phillips Director March 15, 2001
- ------------------------------
Dean Phillips
/S/ Ward Sauvage Director March 15, 2001
- ------------------------------
Ward Sauvage
/S/ James A. Senty Director March 15, 2001
- ------------------------------
James A. Senty
/S/ Joseph E. Reid Director March 15, 2001
- ------------------------------
Joseph E. Reid
/S/ William J. Krysiak Vice President - Finance (Principal Financial and March 15, 2001
- ------------------------------
William J. Krysiak Accounting Officer)
62