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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, 1999 or
[_] Transition report pursuant to section 13 or 15(d) of the Securities
Exchange Act of 1934 [No Fee Required] for the transition period from
_________________ to _________________
Commission file number 1-10389
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WESTERN GAS RESOURCES, INC.
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(Exact name of registrant as specified in its charter)
Delaware 84-1127613
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
12200 N. Pecos Street, Denver, Colorado 80234-3439
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(Address of principal executive offices) (Zip Code)
(303) 452-5603
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Registrant's telephone number, including area code
No Changes
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(Former name, former address and former fiscal year,
if changed since last report)
Title of each class Name of exchange on which registered
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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 _____
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The aggregate market value of voting common stock held by non-affiliates of the
registrant on March 1, 2000 was $274,636,297.
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 19, 2000.
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. [_]
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, Storage and Transmission................ 7
Significant Acquisitions, Projects and Dispositions................ 9
Marketing.......................................................... 11
Producing Properties............................................... 13
Environmental...................................................... 14
Competition........................................................ 15
Regulation......................................................... 15
Employees.......................................................... 16
3. Legal Proceedings.................................................... 16
4. Submission of Matters to a Vote of Security Holders.................. 16
II. 5. Market for Registrant's Common Equity and Related Stockholder Matters 17
6. Selected Financial Data.............................................. 18
7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.............................................. 20
8. Financial Statements and Supplementary Data.......................... 30
9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure............................................... 62
III. 10. Directors and Executive Officers of the Registrant................... 62
11. Executive Compensation............................................... 62
12. Security Ownership of Certain Beneficial Owners and Management....... 62
13. Certain Relationships and Related Transactions....................... 62
IV. 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K..... 62
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 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 systems and
processing and treating facilities in order to provide our customers with a
broad range of services from the wellhead to the sales delivery point.
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 various sized independent producers.
.Production--We develop and, in limited cases, explore for natural gas,
primarily with third-party producers. We participate in exploration and
production in order 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 storage, 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,
----------------------------------------------------------------------------
1999 % 1998 % 1997 %
---------- ------------ ---------- ------------ ---------- ------------
Sale of gas...................................... $1,501,066 78.6 $1,611,521 76.1 $1,657,479 69.6
Sale of NGLs..................................... 346,819 18.1 449,696 21.3 611,969 25.7
Processing, transportation and storage revenues.. 48,994 2.6 44,743 2.1 40,906 1.7
Sale of electric power........................... - - 20 - 59,477 2.5
Other, net....................................... 13,845 .7 11,108 .5 10,714 5
---------- ------------ ---------- ------------ ---------- ------------
$1,910,724 100.0 $2,117,088 100.0 $2,380,545 100.0
========== ========== ========== ========== ========== ============
In order to reduce our overall debt level and provide us with additional
liquidity to fund our key growth opportunities, in 1998 we sold our Edgewood
processing plant and our interest in the production served by this facility and
our Perkins gas gathering and processing facility for an aggregate of $77.8
million. In April 1999, we sold our Katy facility and a portion of the
associated natural gas inventory for gross proceeds of $111.7 million and our
Giddings facility for gross proceeds of $36.0 million. In June 1999, we sold our
MiVida treating facility for gross proceeds of $12.0 million and in December
1999, we sold our Black Lake facility and related reserves for gross proceeds of
$7.8 million. As a result of these 1999 sales our total debt was reduced from
$504.9 million at December 31, 1998 to $378.3 million at December 31, 1999.
3
Business Strategy
Our long-term business plan is to increase our profitability by: (i)
optimizing the profitability of existing operations; (ii) entering into
additional agreements with third-party producers who dedicate acreage to our
gathering and processing operations; and (iii) investing in projects or
acquiring assets that complement and extend our core natural gas gathering,
processing, production and marketing businesses.
Capital expenditures related to existing operations were approximately $81.5
million during 1999. This included approximately $45.8 million related to
gathering, processing and pipeline assets and approximately $28.8 million for
the acquisition of undeveloped acreage and development of gas reserves in the
Powder River basin.
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. In 1999, we spent approximately $40.5
million on additional well connections and compression and gathering
system expansions. We increased throughput levels at our facilities from
895 MMcf/D in 1993 to 1,214 MMcf/D in 1999.
.increasing our efficiency through replacing outdated equipment and the
consolidation of existing facilities. Replacing and upgrading measurement
and compression equipment allows us to minimize maintenance costs, fuel
consumption and field operating costs. For example, in 2000 we will begin
the replacement of dated compression at our Midkiff facility. This upgrade
will result in lower maintenance costs and by decreasing our fuel
consumption, will increase the natural gas available for sale.
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 will allow us the opportunity to consolidate
our operations in Oklahoma 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
outright sale.
.controlling operating and overhead expenses. In 1999, largely as a result of
asset divestitures, and a subsequent restructuring of our operational and
administrative organization, our plant operating and selling and
administrative expenses were reduced by approximately $20.0 million as
compared to those incurred in 1998.
Increase Dedicated Acreage
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 continually seek to obtain production from new wells and newly
dedicated acreage in order to replace declines in existing reserves that are
dedicated for gathering and processing at our facilities. We have increased our
dedicated estimated reserves from 2.3 Tcf at December 31, 1994 to 2.8 Tcf at
December 31, 1999. In 1999, including the reserves associated with our joint
ventures and partnerships and excluding the reserves associated with the
facilities sold during this period, we connected new reserves to our facilities
to replace approximately 142% of throughput. In order to obtain additional
dedicated acreage and to secure contracts on favorable terms, we may participate
to a limited extent with producers in exploration and production activities. For
the same reason, we may also offer to sell an ownership interest in our
facilities to selected producers.
4
Expansion of Core Business
We will continue to 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. During 1999, the majority of our capital budget was spent in
the Powder River basin of Wyoming and in southwest Wyoming. These projects
included:
.continued development of Powder River basin coal bed methane reserves to
increase natural gas production and throughput at our existing gathering
and transportation facilities;
.completion of the Fort Union gathering pipeline and treater, which will
enable us and others to increase gas production in the Powder River basin
and connect to major interstate pipelines for transportation; 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, contain forward-
looking statements within the meaning of the Private Securities Litigation
Reform Act of 1995, which can be identified by the use of forward-looking
terminology, such as "may," "intend," "will," "expect," "anticipate,"
"estimate," or "continue" or the negative thereof or other variations thereon or
comparable terminology. This Form 10-K contains forward-looking statements
regarding the expansion of our gathering operations, our project development
schedules, 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 dedicated to
our facilities. In addition to the important factors referred to herein,
numerous other factors affecting the gas processing industry generally and in
the markets for gas and NGLs in which we operate, 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, 1999. We also own and operate several smaller treating,
processing and transmission facilities located in the same areas as our other
facilities.
Average for the Year Ended
December 31, 1999
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)............ 1997 86 350 83 79 -
Giddings Gathering (14)........ 1979 - - 48 31 66
Gomez Treating................. 1971 385 280 109 101 -
Midkiff/Benedum................ 1955 2,140 165 143 92 877
Mitchell Puckett Gathering..... 1972 86 120 115 75 2
MiVida Treating (6)(16)........ 1972 - - 46 44 -
Rosita Treating(20)............ 1973 - - 42 - -
Louisiana
Black Lake (18)................ 1966 - - 11 6 17
Toca (7)(8).................... 1958 - 160 88 83 71
Wyoming
Coal Bed Methane
Gathering..................... 1990 444 223 122 87 -
Fort Union Gas Gathering(17)... 1999 106 450 14 14 -
Granger (7)(9)(10)............. 1987 471 235 156 139 285
Hilight Complex (7)............ 1969 626 80 19 14 92
Kitty/Amos Draw (7)............ 1969 313 17 12 8 49
Lincoln Road (10).............. 1988 149 50 24 22 23
Newcastle(7)................... 1981 146 5 2 2 18
Red Desert(7).................. 1979 111 42 17 15 29
Reno Junction (9).............. 1991 - - - - 51
Oklahoma
Arkoma......................... 1985 72 8 7 7 -
Chaney Dell.................... 1966 2,050 180 60 47 190
Westana (19)................... 1986 845 45 67 57 80
New Mexico
San Juan River (6)............. 1955 140 60 26 20 26
Utah
Four Corners Gathering......... 1988 104 15 3 4 14
--------- ----------- ----------- ----------- -----------
Total......................... 8,274 2,485 1,214 947 1,890
========= =========== =========== =========== ===========
Average for the Year Ended
December 31, 1999
Interconnect --------------------------
and Pipeline Gas
Storage and Year Placed Transmission Capacity Throughput
Transmission Facilities (1) In Service Miles(2) (MMcf/D)(2) (MMcf/D)(4)
- --------------------------------- ----------- ------------ ----------- -----------
Katy Facility (11) (14).......... 1994 - - 244
MIGC (12)(15).................... 1970 245 130 162
MGTC (13)........................ 1963 252 18 12
------------ ----------- -----------
Total.......................... 497 148 418
============ =========== ===========
Footnotes on following page.
6
(1) Our interest in all facilities is 100% except for Midkiff/Benedum (73%);
Black Lake (69%); Lincoln Road (72%); Westana Gathering Company (50%);
Newcastle (50%) and Fort Union Pipeline (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, interconnect and transmission miles, gas
storage capacity and pipeline capacity are as of December 31, 1999.
(3) Gas throughput capacity is as of December 31, 1999 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,
aggregate volumes delivered over the header at the Katy Facility 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 transmission 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 and our joint venture partner at the Lincoln Road facility have agreed
to process all gas at our Granger facility so long as there is available
capacity at the Granger facility. Accordingly, operations at the Lincoln
Road facility have been temporarily suspended since January 1999.
(11) Hub and gas storage facility.
(12) MIGC is an interstate pipeline located in Wyoming and is regulated by the
Federal Energy Regulatory Commission.
(13) MGTC is a public utility located in Wyoming and is regulated by the Wyoming
Public Service Commission.
(14) This facility was sold in April 1999.
(15) Pipeline capacity represents capacity at the Powder River junction only and
does not include northern delivery points.
(16) This facility was sold in June 1999.
(17) This gathering pipeline and treater became operational during September
1999.
(18) This facility and related reserves were under contract for sale at the end
of 1999. The transaction closed in January 2000.
(19) We acquired the remaining 50% interest in Westana Gathering Company in
February 2000.
(20) This facility was shut down effective December 31, 1999 and will be
dismantled and sold.
We expect capital expenditures related to existing operations to be
approximately $89.7 million during 2000, consisting of the following: (i)
approximately $49.7 million related to gathering, processing and pipeline
assets, of which $8.0 million is for maintaining existing facilities and $9.8
million for acquisition of the remaining 50% in the Westana Gathering Company;
(ii) approximately $38.0 million related to exploration and production
activities; and (iii) approximately $2.0 million for miscellaneous items.
Overall, capital expenditures in the Powder River basin coal bed methane
development and in southwest Wyoming operations represent 50% and 11%,
respectively, of the total 2000 budget.
Gas Gathering, Processing, Storage and Transmission
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 two of
our plants are able to process and treat 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.
7
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 purchasing existing systems from third parties, by
connecting additional wells, through internally developed projects or through
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. There has been a reduction in
drilling activity, primarily in basins that produce oil and casinghead gas, from
levels that existed in prior years. 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 policy of the federal government and the
availability of foreign oil and gas, none of which are within our control. We
have increased our dedicated estimated reserves from 2.3 Tcf at December 31,
1994 to 2.8 Tcf at December 31, 1999. In 1999, including the reserves associated
with our joint ventures and partnerships and excluding the reserves associated
with the facilities sold during this period, we connected new reserves to our
facilities to replace approximately 142% of throughput. In order to obtain
additional dedicated acreage and to secure contracts on favorable terms, we may
participate to a limited extent with producers in exploration and production
activities. For the same reason, we may also offer to sell an ownership interest
in our facilities to selected producers.
Substantially all gas flowing through our gathering, processing and treating
facilities is supplied under long-term contracts providing for the purchase,
treating or processing of natural gas for periods ranging from five to twenty
years, using three basic contract types. Approximately 67% of our plant
facilities' gross margins, or revenues at the plants less product purchases, for
the year ended December 31, 1999 resulted from percentage-of-proceeds agreements
in which we are typically responsible for arranging for the transportation and
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 permits us and the producers to share proportionally in price changes.
Approximately 22% of our plant facilities' gross margins for the year ended
December 31, 1999 resulted from contracts that are primarily fee-based whereby
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
curtail production. The proportion of fee-based contracts is expected to
increase as the volumes from the Powder River basin coal bed methane development
and southwest Wyoming increase. See further discussion in "-Significant
Acquisitions, Projects and Dispositions."
Approximately 11% of our plant facilities' gross margins for the year ended
December 31, 1999 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 the
Colorado Interstate Gas Pipeline, the Williston Basin Interstate Pipeline, the
Pony Express Pipeline, Wyoming Interstate Gas and MGTC. During July 1998, MIGC
received approval from the FERC to increase its pipeline capacity from 90 MMcf
per day to 130 MMcf per day. 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 at rates that are subject to the approval of the
Wyoming Public Service Commission.
8
Significant Acquisitions Projects and Dispositions
Our significant acquisitions, projects and dispositions since January 1, 1996
are:
Coal Bed Methane. We continue to develop our Powder River basin coal bed
methane natural gas gathering system and our coal seam gas reserves in Wyoming.
We have acquired drilling rights on approximately 980,000 gross acres, or
466,000 net acres, in the basin. On approximately 18% of this acreage position,
we have established proven developed and undeveloped reserves. Our production is
derived primarily from wells drilled to depths of 400 to 1,200 feet. Together
with our partner, we drilled 583 gross wells, or 274 net wells, in 1999. In
2000, we expect to increase our drilling schedule to approximately 800 gross
wells, or 376 net wells, the majority of which are on locations with proven,
undeveloped reserves. The average drilling, completion and gathering cost for
our coal bed methane wells is approximately $70,000 to $90,000 with reserves per
well of approximately 320 MMcf. As deeper wells are drilled, the average cost
and reserves per well are expected to increase. Production of coal bed methane
from the Powder River basin has been expanding, and approximately 180 MMcf/D of
gas volumes in the fourth quarter of 1999 were being produced by several
operators in the area, including 110 MMcf/D produced by our partner and us. This
compares to 61 MMcf/D produced in January 1998. We transport most of the coal
bed methane gas through our MIGC interstate pipeline located in Wyoming, for
redelivery to gas markets in the Rocky Mountain and Midwest regions of the
United States.
Future drilling on federal acreage will be delayed subject to completion of an
Environmental Impact Statement. This study is expected to take approximately two
years. Our drilling plans for 2000 and 2001 are not expected to be substantially
impacted by this study due to our large inventory of non-federal drilling
locations. In addition, the Wyoming Department of Environmental Quality is
evaluating changes in the standards for surface water discharge and the
reclassification of certain drainage areas. These modifications may be approved
within the second quarter of 2000 which will allow the issuance of previously
requested water permits and expedite the issuance of future water permits.
However, we can make no assurance that the conditions under which permits are
granted will not impact the level of drilling or the timing of production.
Our capital budget in this area provides for expenditures of approximately
$45.0 million during 2000. This capital budget includes approximately $34.3
million for drilling costs for our interest in approximately 800 wells,
production equipment and undeveloped acreage and $10.7 million for compression.
In March 2000, we entered into a ten-year operating lease agreement for the
leasing of as many as ten compressors. Depending upon future drilling success,
we may need to make additional capital expenditures to continue expansion in
this basin. However, because of drilling and other uncertainties beyond our
control, we can make no assurance that we will incur this level of capital
expenditure or that we will make additional capital expenditures. In each of the
years ended December 31, 1999 and 1998, we expended approximately $51.4 million
and $46.7 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 from the jointly-owned properties within the AMI under a long-term
fee based agreement.
In December 1998, we joined with other industry partners to form Fort Union
Gas Gathering, L.L.C., to build 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 new gathering header has a capacity
of approximately 450 MMcf/D of natural gas with expansion capability and in
February 2000 it had throughput of approximately 100 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 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.
9
Southwest Wyoming. The United States Geologic Survey estimates that the
Greater Green River basin contains over 120 Tcf of unrecovered natural gas
reserves. Our facilities in southwest Wyoming are comprised of the Granger
facility and a 72% ownership interest in the Lincoln Road facility, or
collectively the Granger Complex. These facilities have a combined operational
capacity of 225 MMcf/D and processed an average of 180 MMcf/D in 1999. Our
capital budget in this area provides for expenditures of approximately $9.7
million during 2000. This capital budget includes approximately $3.4 million for
drilling costs and production equipment and approximately $6.3 million related
to the gathering systems and plant facilities. Because of drilling and other
uncertainties beyond our control, we can provide no assurance that we will incur
this level of capital expenditure or that we will make future capital
expenditures. During the years ended December 31, 1999 and 1998, we expended
approximately $12.4 million and $16.0 million, respectively, on this project.
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 1999, we participated in 21 gross
development wells, or 4 net development wells, in the Jonah field of southwest
Wyoming. We also participated in 13 gross exploratory wells, or 4 net
exploratory wells, in the Hoback basin. We expect to participate in the drilling
of 13 gross wells, or 2 net wells in this area during 2000. The average drilling
and completion costs per gross well in this area are approximately $2.2 million
and the average well depth in this area approximates 13,000 feet.
Additionally, we entered into two separate agreements with an affiliate of the
producer to sell an undivided interest in the following assets. Under the first
agreement, in February 1998, we sold a 50% undivided interest in a small portion
of the Granger gathering system that services the AMI for approximately $4.0
million. This amount approximated our cost in this facility. We expect to
install jointly additional gathering assets in this area as needed. Under the
second agreement, we granted the same entity the option to purchase up to 50% of
the Granger Complex. In conjunction with this agreement, in February 1998, we
received a $1 million non-refundable option payment. This option to acquire an
interest in these facilities expired in the fourth quarter of 1998.
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 will recognize a
pre-tax gain on the sale, subject to final accounting adjustment, of
approximately $5.5 million in the first quarter of 2000.
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 constructed the Bethel
treating facility for a total cost of approximately $102.8 million with a
throughput capacity of 350 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. As a result, in 1999, the
Bethel treating facility averaged gas throughput of approximately 83 MMcf/D. Due
to the unexpected poor drilling results and reductions in the producers'
drilling budgets, the number of rigs actively drilling for Pinnacle Reefs in
this area has decreased from 18 in July 1998 to three in December 1999.
Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed of,"
requires the review of long-lived assets whenever events or changes in
circumstances indicate that the carrying value of those assets may not be
recoverable. SFAS No.121 also requires that an impairment loss be recognized
when the carrying amount of an asset exceeds its fair market value or its
expected future undiscounted net cash flows. 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 such an evaluation of the Bethel
treating facility 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.
Edgewood. In two transactions which closed in October 1998 we sold our
Edgewood gathering system, including our
10
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 used the proceeds from these sales to repay a
portion of the balances outstanding under the Revolving Credit Facility. After
the accrual of certain related expenses, 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.
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.
Katy. We continue to view access to storage capacity as a significant element
of our marketing strategy. However, as a result of an increase in third-party
storage services available in the marketplace combined with our 1999 business
plan objective of improving our balance sheet, 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. In April 1999, 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 will continue to contract for storage capacity. Accordingly, we
entered into a long-term agreement with the purchaser for approximately 3 Bcf of
storage capacity at market rates.
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.
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
accrued in the fourth quarter of 1999.
Westana. In February 2000, we acquired the remaining 50% interest in this
partnership for a gross purchase price of $10.8 million. This transaction is
effective January 1, 2000 and is subject to final accounting adjustment.
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 outright sale.
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 in 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, 1999, our gas sales volumes averaged
1.9 Bcf/D. Third-party sales and gas storage, combined with the stable supply of
gas from our facilities, 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. Most of our current sales
contracts range from a few days to two years. During 1997, we created a wholly
owned subsidiary to operate a marketing office in Calgary, Alberta. The Calgary
office markets third party gas volumes in Canada, provides us with information
regarding gas supplies being transported from Canada and establishes a presence
in an evolving gas market.
In general, we do not expect to increase our third-party sales volumes in 2000
significantly from levels achieved during the year ended December 31, 1999. Our
2000 gas marketing plan emphasizes growth through our asset base and storage and
transportation capacities which we control.
11
We continue to view access to storage capacity as a significant element 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, 1999, we had contracts in
place for approximately 29.3 Bcf of storage capacity for resale during periods
when prices are favorable. The fees associated with these contracts currently do
not exceed $.61 per Mcf and the associated contract periods range from two
months to six years. As of December 31, 1999, we also had contracts for
approximately 606 MMcf/D of firm transportation; approximately 30% of which
expire during 2000. The fees associated with these contracts do not exceed $.50
per Mcf, and the associated contract periods range from ten months to twelve
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 held gas in storage and in imbalances at various facilities of
approximately 13.7 Bcf at an average cost of $2.40 per Mcf at December 31, 1999
compared to 19.9 Bcf at an average cost of $2.13 per Mcf at December 31,1998. At
December 31, 1999, we had hedging contracts in place for anticipated sales of
approximately 18.6 Bcf of stored gas at a weighted average price of $2.41 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."
During the year ended December 31, 1999, we sold gas to approximately 351 end-
users, pipelines, LDCs and other customers. No single gas customer accounted for
more than 4% of consolidated revenues for the year ended December 31, 1999.
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 31,1999, NGL sales
averaged 2,885 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 decreased sales to third parties by approximately 1,325 MGal/D for the year
ended December 31, 1999 compared to 1998. In general, we do not anticipate that
sales to third parties in 2000 will vary significantly from those experienced in
1999. 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.
We lease NGL storage space at major trading locations, primarily near Houston
and in central Kansas, in order to store products for resale during periods when
prices are favorable and to facilitate the distribution of products. In
addition, as of December 31, 1999, we had contracts in place for approximately
26,250 MGal of storage capacity. The base fees associated with those contracts
currently do not exceed $.02 per gallon and the associated contract periods
range from two months to three years. Several of the long-term contracts require
an annual renewal and contain provisions requiring us to pay the fees associated
with such contracts whether or not the service is used.
We held NGLs in storage of 8,600 MGal, consisting primarily of propane and
normal butane, at an average cost of $.34 per gallon and 16,900 MGal, consisting
primarily of propane and normal butane, at an average cost of $.24 per gallon at
December 31, 1999 and 1998, respectively, at various third-party storage
facilities. At December 31, 1999, we had no significant hedging contracts in
place for anticipated sales of stored NGLs.
12
NGL sales were made to approximately 132 different customers for the year
ended December 31, 1999. One customer accounted for approximately 19% of our
consolidated revenues from the sale of NGLs, or 3% of total consolidated
revenue, for the year ended December 31, 1999. This customer is a large
integrated utility. We also derive revenues from contractual marketing fees
charged to some producers for NGL marketing services. For the year ended
December 31, 1999, these fees were less than 1% of our consolidated revenues.
Power Marketing. In July 1996, the FERC issued its final order requiring
investor-owned electric utilities to provide open access for wholesale
transmission. This action allowed companies to participate in a market
previously controlled by electric utilities. During 1996 and 1997, we traded
electric power in the wholesale market and entered into transactions that
arbitrage the value of gas and electric power. During the second half of 1997,
we elected to discontinue wholesale trading of electric power, due to a lack of
profitability.
Producing Properties
Primarily to secure additional gas supply for our facilities, we selectively
participate in exploration and production activities. Beginning in 1997, we
substantially increased our investment in the acquisition of undeveloped acreage
and development of the Powder River coal bed methane and during 1999 we invested
$28.8 million in this project. This play has now developed into one of our most
significant long-term holdings. See "Business--Significant Acquisitions,
Projects and Dispositions--Coal Bed Methane" and "--Southwest Wyoming." Revenues
derived from our producing properties comprised approximately 1.7%, 1.3% and
1.3% of consolidated revenues for the years ended December 31, 1999, 1998 and
1997, respectively. As a result of the increased investment in the Powder River
coal bed methane, we expect the revenues derived from our producing properties
to continue to increase. We will also consider investing in other exploration
and production prospects that we consider to be low risk and complementary to
our gathering and processing business.
The following table provides a summary of our net annual production volumes:
December 31,
-------------------------------------------------
1999 1998 1997
--------------- --------------- ---------------
Gas Oil Gas Oil Gas Oil
State/Basin (MMcf) (MBbl) (MMcf) (MBbl) (MMcf) (MBbl)
- -------------------- ------- ------ ------- ------ ------- ------
Colorado............ 332 3 274 2 243 6
Louisiana (1)....... 2,270 64 2,810 75 4,760 108
Texas (1)........... 62 4 1,787 5 6,092 21
Wyoming:
Coal Bed Methane.. 12,766 - 7,136 - 1,751 -
All Other......... 2,558 41 3,283 40 1,752 19
------ --- ------ --- ------ ---
Total............... 17,988 112 15,290 122 14,598 154
====== === ====== === ====== ===
(1) We sold our producing properties in Louisiana during 1999 and our producing
properties in Texas during 1998.
13
The following table provides a summary of our proved developed and proved
undeveloped net reserves:
December 31,
----------------------------------------------------
1999 1998 1997
---------------- ---------------- ----------------
Gas Oil Gas Oil Gas Oil
State/Basin (MMcf) (MBbl) (MMcf) (MBbl) (MMcf) (MBbl)
- -------------------- -------- ------ -------- ------ -------- ------
Colorado............ 6,452 40 2,278 8 1,185 5
Louisiana (1)....... - - 10,234 190 30,615 485
Texas (1)........... - - - - 45,370 -
Wyoming:
Coal Bed Methane.. 236,277 - 193,010 - 126,812 -
All Other......... 29,089 289 33,408 359 18,833 317
------- --- ------- --- ------- ---
Total............... 271,818 329 238,930 557 222,815 807
======= === ======= === ======= ===
(1) We sold our producing properties in Louisiana during 1999 and our producing
properties in Texas during 1998.
As a result of a review of the reserves at our Black Lake facility, and by
comparing the net book value of the assets to the undiscounted expected future
cash flows, which management determined by applying future prices estimated over
the lives of the associated reserves, we wrote down the Black Lake reserves and
the processing facility associated with such reserves in accordance with SFAS
No. 121 to the net present value of expected cash flows discounted using an
interest rate commensurate with the risk associated with the underlying asset.
Accordingly, we recognized a pre-tax, non-cash loss of $28.8 million for the
year ended December 31, 1998. In addition, we recognized a pre-tax, non-cash
loss on the impairment of property and equipment, primarily related to our Black
Lake facility and Sand Wash basin assets, of $34.6 million for the year ended
December 31, 1997.
We employ a total staff of eight 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 for 1999 has been audited by Netherland, Sewell & Associates,
Inc.
Our 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
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.
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, five 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.
14
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 "grandfathered" air
emissions sources within the State of Texas. A "grandfathered" air emissions
source is one that does not need a state operating permit because it was
constructed prior to 1971. We operate a number of these sources within the State
of Texas, including portions of our Midkiff plant and many of our compressors.
The recommendations proposed by the committee would create a voluntary
permitting program for grandfathered sources, including incentives to
participate, like the ability to operate these sources in a flexible manner. It
is not clear which of the committee's recommendations, if any, that the
Commission will implement and it is not possible to assess the potential effect
on us until final regulations are issued.
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 $2.6 million for the year ended
December 31, 1999, including approximately $500,000 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 efficiency, reliability, availability
of transportation and ability to obtain a satisfactory price for the producers'
natural gas. Competition for sales customers is primarily based upon reliability
and price of deliverable 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
based primarily on price against companies capable of providing such alternative
fuels. Our competitors for obtaining leaseholds include major and large
independent oil companies with knowledgeable technical staffs as well as smaller
independent oil companies and brokers. 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 require additional security such as letters of credit that are
not required of certain of our competitors. If the additional security is
required, our marketing margins and volumes would be adversely impacted.
Regulation
Our purchase and sale of natural gas and the fees we receive for gathering and
processing have generally not been subject to regulation and, therefore, except
as constrained by competitive factors, we have considerable pricing flexibility.
However, many aspects of our gathering, processing, marketing and transportation
of natural gas and NGLs 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 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.
15
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.
Employees
At December 31, 1999, we employed approximately 646 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, 1999.
16
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
As of March 1, 2000, there were 32,166,247 shares of Common Stock outstanding
held by 281 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
------- -------
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
1998
Fourth Quarter.............. 9 7/8 5 5/16
Third Quarter............... 15 1/8 8
Second Quarter.............. 19 5/8 13 7/8
First Quarter............... $22 1/8 $15 7/8
We paid annual dividends on our Common Stock aggregating $.20 per share during
the years ended December 31, 1999 and 1998. We have declared a dividend of $.05
per share of Common Stock for the quarter ending March 31, 2000 to holders of
record as of March 31, 2000. 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, 1999, availability under this covenant was approximately
$12.0 million.
17
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 1999. The data for the three years ended
December 31, 1999, 1998 and 1997 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, 1996 and 1995 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,
--------------------------------------------------------------------------
1999 1998 1997 1996 1995
---------- ---------- ---------- ---------- ----------
(000s, except per share amounts and operating data)
Statement of Operations:
Revenues.................... $1,910,724 $2,117,088 $2,380,545 $2,088,262 $1,697,046
Gross profit (a)............ 37,487 66,568 93,755 105,479 75,211
Income (loss) before income
taxes..................... (25,184)(b) (105,623)(b) 2,220 (b) 41,631 (8,266)(c)
Provision (benefit) for
income taxes.............. (9,167) (38,418) 733 13,690 (2,158)
Income (loss) before
extraordinary items....... (16,017)(b) (67,205)(b) 1,487 (b) 27,941 (6,108)(c)
Extraordinary charge for
early extinguishment of
debt...................... (1,107)(d) - - - -
Net income (loss)........... (17,124)(b) (67,205)(b) 1,487 (b) 27,941 (6,108)(c)
Earnings (loss) per share of
common stock.............. (.86) (2.42) (.28) .66 (.84)
Earnings (loss) per share of
common stock - assuming
dilution.................. (.86) (2.42) (.28) .66 (.84)
Other financial data:
Net cash provided by
operating activities...... 95,184 (35,570) 114,755 168,266 86,373
EBITDA, as adjusted(e)...... 89,913 79,291 118,404 137,233 115,141
Capital expenditures........ 81,489 105,216 198,901 74,555 78,521
Balance Sheet Data
(at year end):
Total assets................ 1,049,486 1,219,377 1,348,276 1,361,631 1,193,997
Long-term debt.............. 378,250 504,881 441,357 379,500 529,500
Stockholders' equity........ 349,743 385,216 468,112 480,467 371,909
Dividends on preferred
stock..................... 10,439 10,439 10,439 10,439 15,431
Dividends on common stock... 6,426 6,430 6,427 5,472 5,153
Operating Data:
Average gas sales (MMcf/D).. 1,900 2,200 1,975 1,794 1,572
Average NGL sales (MGal/D).. 2,885 4,730 4,585 3,744 2,890
Average gas volumes
gathered (MMcf/D).......... 1,214 1,162 1,229 1,171 1,020
Facility capacity (MMcf/D).. 2,485 2,237 2,302 1,940 1,907
Average gas prices ($/Mcf).. $ 2.17 $ 2.01 $ 2.30 $ 2.19 $ 1.53
Average NGL prices ($/Gal).. $ .33 $ .26 $ .36 $ .41 $ .31
(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
18
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, and $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) In accordance with SFAS No. 121, we recognized a pre-tax, non-cash loss for
the year ended December 31, 1995 on the impairment of property and equipment
of $17.6 million, or $12.4 million after-tax. Also, we implemented a cost
reduction program to reduce operating and selling and administrative
expenses. As a result of this program, a $2.1 million pre-tax, or $1.3
million after-tax, restructuring charge was incurred, primarily related to
employee severance costs.
(d) We recognized an extraordinary loss on the early extinguishment of long-term
debt in the second quarter of 1999 of $1.8 million pre-tax, or $1.1 million
after-tax, primarily related to the prepayment of indebtedness with the
proceeds of the subordinated debt offering.
(e) Reflects income before interest expense, income taxes, depreciation,
depletion and amortization, $1.2 million, $108.5 million, $34.6 million and
$17.6 million of non-cash impairment losses related to certain oil and gas
assets and plant facilities in the fourth quarter of 1999, 1998, 1997 and
1995, respectively, in connection with SFAS No. 121, (gains) or losses on
sales of assets of $29.8 million, $16.5 million, $4.7 million, $2.0 million,
$(1.2) million for each of the years ended December 31, 1999, 1998, 1997,
1996, 1995, respectively and a $1.1 million after-tax charge for loss on the
early extinguishment of long-term debt in the second quarter of 1999. 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.
19
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, 1999, 1998 and 1997. Certain prior year amounts have
been reclassified to conform to the presentation used in 1999. 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, 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 - basic and diluted... (.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
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. We have
entered into futures positions for a portion of our equity gas for 2000. See
further discussion in "-Liquidity and Capital Resources - Risk Management."
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. We have entered into
futures positions for a portion of our equity production for 2000. See further
discussion in "-Liquidity and Capital Resources - Risk Management."
20
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. We expect marketing
margins to remain at the $.01 per Mcf level in 2000.
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 $.5 million 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 loss from early extinguishment of long-term debt
in the second quarter of 1999.
Year ended December 31, 1998 compared to year ended December 31, 1997
(000s, except per share amounts and operating data)
Year Ended
December 31,
------------------------ Percent
1998 1997 Change
----------- ----------- -------
Financial results:
Revenues............................................. $2,117,088 $2,385,260 (11)
Gross profit......................................... 66,568 93,775 (29)
Net income (loss).................................... (67,205) 1,487 -
Loss per share of common stock - basic and diluted... (2.42) (.28) (764)
Net cash provided by (used in) operating activities.. $ (35,570) $ 114,755 -
Operating data:
Average gas sales (MMcf/D)........................... 2,200 1,975 11
Average NGL sales (MGal/D)........................... 4,730 4,585 3
Average gas prices ($/Mcf)........................... $ 2.01 $ 2.30 (137)
Average NGL prices ($/Gal)........................... $ .26 $ .36 (28)
Net income decreased $68.7 million for the year ended December 31, 1998
compared to 1997. The decrease in net income for the year was primarily due to a
$69.0 million, after-tax, charge for impairment recorded 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 $46.0 million for the
year ended December 31, 1998 compared
21
to 1997. Average gas sales volumes increased 225 MMcf/D to 2,200 MMcf/D for the
year ended December 31, 1998 compared to 1997, primarily due to an increase in
the sale of gas purchased from third parties. The increase in volumes sold was
more than offset by a decrease in average gas prices. Average gas prices
realized by us decreased $.29 per Mcf to $2.01 per Mcf for the year ended
December 31, 1998 compared to 1997. Included in the realized gas price is
approximately $71,000 of loss recognized in the year ended December 31, 1998
related to futures positions on equity volumes. See further discussion in "--
Liquidity and Capital Resources--Risk Management Activities."
Revenues from the sale of NGLs decreased approximately $162.3 million for the
year ended December 31, 1998 compared to 1997. Average NGL sales volumes
increased 145 MGal/D to 4,730 MGal/D for the year ended December 31, 1998
compared to 1997, primarily due to an increase in the sale of NGLs purchased
from third parties. The increase in sales volumes was more than offset by a
decrease in average NGL prices. Average NGL prices realized by us decreased $.10
per gallon to $.26 per gallon for the year ended December 31, 1998 compared to
1997. Included in the realized NGL price was approximately $7.4 million of gain
recognized in the year ended December 31, 1998 related to futures positions on
equity volumes. See further discussion in "--Liquidity and Capital Resources--
Risk Management Activities."
Revenue associated with electric power marketing decreased approximately $59.5
million for the year ended December 31, 1998 compared to 1997, as we
discontinued wholesale trading of electric power in 1997, due to a lack of
profitability.
Other net revenue increased approximately $12.2 million for the year ended
December 31, 1998 compared to 1997. The increase was primarily due to a $14.9
million gain on the sale of our Perkins facility and a $1.0 million option
payment received from RIS in connection with the potential sale of a portion of
our assets in southwest Wyoming. These increases were offset by decreases of
approximately $2.8 million in earnings from our investments in joint ventures,
primarily due to the decreases in product prices and the sale of our interest in
Redman Smackover. See further discussion at "Business--Significant Acquisitions,
Projects and Dispositions--Southwest Wyoming."
The reduction in product purchases of $232.1 million to $1.9 billion for the
year ended December 31, 1998 compared to 1997, was primarily due to a decrease
in commodity prices. Overall, combined product purchases as a percentage of
sales of all products increased from 92% to 93% for the year ended December 31,
1998 compared to 1997. Over the past several years, we have experienced
narrowing margins in our third-party sales as a result of increasing
competitiveness of the natural gas marketing industry. During the year ended
December 31, 1998, margins on the sale of third-party gas declined and averaged
approximately $.02 per Mcf compared to approximately $.03 per Mcf for 1997.
Contributing to the increase in the product purchase percentage for the year
ended December 31, 1998 were higher payments related to our "keepwhole"
contracts at our Granger facility. Under a "keepwhole" contract, our margin is
reduced when the value of NGLs declines relative to the value of gas. Also
included in product purchases were lower of cost or market writedowns, primarily
related to NGL inventories, of $826,000 and $1.1 million for the years ended
December 31, 1998 and 1997, respectively.
Plant operating expense increased approximately $7.2 million for the year
ended December 31, 1998 compared to 1997. The increase was primarily due to
compression costs associated with the increasing Powder River basin coal bed
methane production activities and expenses incurred at the Bethel Treating
facility, which became partially operational during the third quarter of 1997.
Interest expense increased $6.1 million for the year ended December 31, 1998
compared to 1997. The increase is the result of less interest capitalized to
capital projects, primarily the Bethel Treating facility, and larger debt
balances outstanding during the year ended December 31, 1998 compared to 1997.
The larger debt balances resulted primarily from higher product inventory
positions, capital expenditures associated with the Bethel Treating facility and
reduced cashflow from operations.
Business Strategy
Our long-term business plan is to increase our profitability by: (i)
optimizing the profitability of existing operations; (ii) entering into
additional agreements with third-party producers who dedicate acreage to our
gathering and processing operations; and (iii) investing in projects or
acquiring assets that complement and extend our core natural gas gathering,
processing, production and marketing businesses.
22
We continually seek to improve the profitability of our existing operations by
increasing natural gas throughput levels through new well connections and
expansion of gathering systems, increasing our efficiency through the
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 acreage 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 that are dedicated for
gathering and processing at our facilities. We have increased our dedicated
estimated reserves from 2.3 Tcf at December 31, 1994 to 2.8 Tcf at December 31,
1999. In 1999, including the reserves associated with our joint ventures and
partnerships and excluding the reserves associated with the facilities sold
during this period, we connected new reserves to our facilities to replace
approximately 142% of throughput. In order to obtain additional dedicated
acreage and to secure contracts on favorable terms, we may participate to a
limited extent with producers in exploration and production activities. For the
same reason, we may also offer to sell an ownership interest in our facilities
to selected producers.
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.
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 1998,
sources of liquidity included the sales of the Perkins facility and the Edgewood
facility and related production. In the second quarter of 1999, we completed the
sales of our Giddings, Katy and MiVida facilities. In connection with the sale
of Katy, we sold gas held in storage at this facility. In December 1999, we
contracted for the sale of the Black Lake facility and related reserves. This
sale closed in January 2000. The total gross proceeds from the asset sales
reported in 1999 was $168.0 million. We used the proceeds from these sales to
reduce debt. Product prices, sales of inventory, the volumes of natural gas
processed by our facilities, the margin on third-party product purchased for
resale, as well as the timely collection of our receivables will affect all
future net cash provided by operating activities. Additionally, our future
growth will be dependent upon obtaining additions to dedicated plant reserves,
acquisitions, new project development, marketing, efficient operation of our
facilities and our ability to obtain 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 and complete our current capital
expenditure program. 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 such capital is 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 such 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
such 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 2000.
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. There has been a reduction in drilling
activity, primarily in basins that produce oil and casinghead gas, from levels
that existed in prior years. However, higher gas prices experienced over the
last several years, improved technology, e.g., 3-D seismic and horizontal
drilling, and increased pipeline capacity from the Rocky Mountain region have
stimulated drilling in the Powder River basin and southwest Wyoming. The overall
level of drilling will depend upon, among other factors, the prices for gas and
oil, the drilling budgets
23
of third-party producers, the energy policy of the federal government 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 Commission for
an aggregate of $200 million of debt securities and preferred stock, along with
the shares of common stock, if any, into which such securities are convertible,
and $62 million of debt securities, preferred stock or common stock.
Our sources and uses of funds for the year ended December 31, 1999 are
summarized as follows (In thousands):
Sources of funds:
Borrowings under revolving credit facility................ $2,115,250
Proceeds from the dispositions of property and equipment.. 148,685
Proceeds from issuance of long-term debt.................. 155,000
Net cash provided by operating activities................. 95,184
Proceeds from exercise of common stock options............ 158
Other..................................................... 88
----------
Total sources of funds.................................. $2,514,365
==========
Uses of funds:
Payments related to long-term debt
(including debt issue costs)............................ $2,406,349
Capital expenditures...................................... 81,489
Dividends paid............................................ 16,865
----------
Total uses of funds..................................... $2,504,703
==========
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
13.7 Bcf at an average cost of $2.40 per Mcf at December 31, 1999 compared to
19.9 Bcf at an average cost of $2.13 per Mcf at December 31, 1998 under storage
contracts at various third-party facilities. At December 31, 1999, we had
hedging contracts in place for anticipated sales of approximately 18.6 Bcf of
stored gas at a weighted average price of $2.41 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 of 8500 MGal, consisting primarily of propane and
normal butane, at an average cost of $.34 per gallon and 16,900 MGal at an
average cost of $.24 per gallon at December 31, 1999 and 1998, respectively, at
various third-party storage facilities. At December 31, 1999, we had no
significant hedging contracts in place for anticipated sales of stored NGLs. One
customer accounted for approximately 19% of our consolidated revenues from the
sale of NGLs, or 3% of total consolidated revenue, for the year ended December
31, 1999. This customer is a large integrated utility.
Capital Investment Program
For the years ended December 31, 1999, 1998 and 1997, we expended $81.5
million, $105.2 million and $198.9 million, respectively, on new projects and
acquisitions. For the year ended December 31, 1999, our expenditures consisted
of the following: (i) $43.3 million for new connects, system expansions and
asset consolidations; (ii) $2.5 million for maintaining existing facilities;
(iii) $34.3 million for exploration and production activities and acquisitions
of undeveloped acreage; and (iv) $1.3 million of miscellaneous expenditures.
We expect capital expenditures related to existing operations to be
approximately $89.7 million during 2000, consisting of the following: (i)
approximately $49.7 million related to gathering, processing and pipeline
assets, of which $8.0 million is for maintaining existing facilities and $9.8
million for acquisition of the remaining 50% in the Westana Gathering Company;
(ii) approximately $38.0 million related to exploration and production
activities; and (iii) approximately $2.0 million for miscellaneous items.
Overall, capital expenditures in the Powder River basin coal bed methane
development and in southwest Wyoming operations represent 50% and 11%,
respectively, of the total 2000 budget.
24
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 five-
year $167 million Revolving Credit Facility, or Tranche B. At December 31, 1999,
$ 46.3 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, 1999,
the interest rate payable on the facility was 7.9%. 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 ratio of EBITDA, excluding certain
non-recurring items, to interest and dividends on preferred stock as of the end
of any fiscal quarter, for the four preceding fiscal quarters, of not less than
1.35 to 1.0 and increasing to 3.25 to 1.0 by December 31, 2002. This facility is
guaranteed and secured via a pledge of the stock of certain of our subsidiaries.
We generally utilize excess daily funds to reduce any outstanding balances on
the Revolving Credit Facility and associated interest expense, and we intend to
continue such practice.
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, 1999 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 April 1999, effective January 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 40% through March 2002 and 35% thereafter. This
amendment also requires an EBITDA to interest ratio of not less than 1.75 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 1.75 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, we are
prohibited from declaring or paying dividends that in the aggregate exceed the
sum of $50 million plus 50% of consolidated net income earned after June 30,
1995, or minus 100% of a net loss, plus the aggregate net cash proceeds received
after June 30, 1995 from the sale of any stock. At December 31, 1999,
approximately $25.6 million was available under this limitation. We financed the
$8.3 million scheduled payment made in October 1999 with amounts available under
the Revolving Credit Facility. Borrowings under the Master Shelf Agreement are
guaranteed and secured via a pledge of the stock of certain of our subsidiaries.
In June 1999, we prepaid approximately $33.3 million of notes outstanding
under the Master Shelf Agreement with proceeds from the offering of the
Subordinated Notes.
1995 Senior Notes. In 1995, we sold $42 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 million of the principal amount
25
outstanding on the 1995 Senior Notes at par. These payments were financed by a
portion of the $37 million Bridge Loan described below and by amounts available
under the Revolving Credit Facility. The remaining principal amount outstanding
of $27 million is due in a single payment in December 2005. The 1995 Senior
Notes are guaranteed and secured via a pledge of the stock of certain of our
subsidiaries. This facility contains covenants similar to the Master Shelf
Agreement. In the second quarter of 1999 and in January 2000, we posted letters
of credit for a total of approximately $11.8 million for the benefit of the
holders of the 1995 Senior Notes.
We are currently paying an annual fee of not more than .65% on the amounts
outstanding on the Master Shelf Agreement and the 1995 Senior Notes. This fee
will continue until we have received an implied investment grade rating on our
senior secured debt. This fee is not assessed on the portion of the 1995 Senior
Notes for which letters of credit are posted.
1993 Senior Notes. In 1993, we sold $50 million of 7.65% Senior Notes, the 1993
Senior Notes, to a group of insurance companies. Scheduled annual principal
payments of $7.1 million on the 1993 Senior Notes were made on April 30 of 1997
and 1998. In February 1999, we prepaid $33.5 million of the total principal
amounts outstanding of $35.6 million at par. These payments were financed by a
portion of the $37 million Bridge Loan. We prepaid the remaining outstanding
principal of $2.1 million in April 1999 with amounts available under the
Revolving Credit Facility.
In connection with the repayments on the Master Shelf Agreement, the 1995
Senior Notes and the 1993 Senior Notes, we incurred approximately $1.8 million
of pre-tax yield maintenance and other charges. These charges are reflected as
an extraordinary loss from early extinguishment of long-term debt in the second
quarter of 1999.
Bridge Loan. In February 1999, in order to finance prepayments of amounts
outstanding on the 1993 and 1995 Senior Notes, we entered into a Bridge Loan
agreement in the amount of $37 million with our agent bank. This facility was
paid in full in April 1999 with proceeds from the sale of the Katy facility.
Senior Subordinated Notes. In June 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. 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 our subsidiaries. In November 1999, we
exchanged the privately placed notes for registered publicly tradable notes
under the same terms and conditions. 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. The Company was in compliance with all covenants in its
debt agreements at December 31, 1999. Taking into account all the covenants
contained in these agreements, we had approximately $110 million of available
borrowing capacity at December 31, 1999. In the second quarter of 1999, we
amended our various financing facilities providing for financial flexibility and
covenant modifications and issued the Subordinated Notes. These amendments were
needed given the depressed commodity pricing experienced in the industry in
general at that time and the disappointing results at our Bethel Treating
facility. We can provide no assurance that further amendments or waivers can be
obtained in the future, if necessary, or that the terms would be favorable to
us. To strengthen our credit ratings and to reduce our overall debt outstanding,
we will continue to dispose of non-strategic assets and investigate alternative
financing sources including the issuance of public debt, project-financing,
joint ventures and operating leases.
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 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
26
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.
We hedged a portion of our estimated equity volumes of gas and NGLs in 2000 at
pricing levels approximating our 2000 operating budget. Our equity hedging
strategy establishes a minimum price while allowing varying levels of market
participation above the minimum. As of February 8, 2000, we had hedged
approximately 42%, or 30,000 MMBtu/day, of our anticipated equity gas for 2000
at a weighted average NYMEX equivalent minimum price of $2.22 per MMBtu and an
additional 31%, or 22,000 MMBtu/day, with collars with a minimum price of $2.10
per MMBtu and a maximum price of $2.44 per MMBtu NYMEX equivalent price.
Additionally, we have hedged approximately 26%, or 25,000 Bbl per month of our
anticipated equity natural gasoline, condensate and crude oil for 2000 using a
collar with a minimum price of $15.00 per Bbl and maximum price of $17.00 per
Bbl NYMEX crude oil monthly average price. We have also hedged approximately
46%, or 195,000 Bbl per month, of our anticipated equity production of NGLs for
2000 with a minimum weighted average Mt. Belvieu composite price of $0.27
per gallon. Finally, we have hedged approximately 27%, or 345,000 Bbls of our
estimated first quarter production of equity NGLs at a weighted average Mt.
Belvieu price of $0.52 per gallon.
At December 31, 1999, we had $600,000 of unrecognized gains in inventory that
will be recognized primarily during the first quarter of 2000 which may be
offset by margins from our related forward fixed price hedges and physical
sales. At December 31, 1999, we had unrecognized net losses of $925,000 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 these trades including predetermined stop-loss
requirements and net open position 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 these
speculative activities for the years ended December 31, 1999 and 1998 were not
material.
Natural Gas Derivative Market Risk
As of December 31, 1999, we 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. As of December 31, 1998, we held a notional
quantity of approximately 370 Bcf of natural gas futures, swaps and options
extending from
27
January 1999 to December 2000 with a weighted average duration of approximately
four months. This was comprised of approximately 178 Bcf of long positions and
192 Bcf of short positions in such 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, 1999, the calculated VaR of our entire natural gas
portfolio of futures, swaps and options was approximately $3.3 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, 1999, the VaR of these type of
transactions for natural gas was approximately $400,000.
Crude Oil and NGL Derivative Market Risk
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 such instruments. As of December 31, 1998, we held a notional
quantity of approximately 177,000 MGal of NGL futures, swaps and options
extending from January 1999 to December 1999 with a weighted average duration of
approximately six months. This was comprised of approximately 129,000 MGal of
long positions and 48,000 MGal of short positions in such instruments.
As of December 31, 1999, we had purchased 25,000 barrels per month of NYMEX
monthly average settlement $15.00 per barrel puts and sold 25,000 barrels per
month of NYMEX monthly average settlement $17.00 calls to hedge a portion of the
Company's equity production of natural gasoline, condensates and crude oil. We
do not hold any crude oil futures, swaps or options for settlement beyond 2000.
As of December 31, 1999, we had purchased 125,000 barrels per month of OPIS
Mt. Belvieu monthly average settlement $0.300 per gallon puts to hedge a portion
of our equity production of propane for 2000.
As of December 31, 1999, we had purchased 70,000 barrels per month of OPIS Mt.
Belvieu monthly average settlement $0.220 per gallon of purity ethane puts to
hedge a portion of our equity production of ethane for 2000.
As of December 31, 1999, we did not hold any NGL futures, swaps or options for
settlement beyond 2000.
As of December 31, 1999, the estimated fair value of the aforementioned crude
oil and NGL options held by us was approximately $(194,000).
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, 1999, the net notional value of such contracts was
approximately $7.5 million in Canadian dollars, which approximates its fair
market value. As of December 31, 1998, the net notional value of such contracts
was approximately $11.0 million in Canadian dollars, which approximated its fair
market value.
Year 2000
Overall, we did not experience any significant disruption of our operations or
computer systems as a result of the Year 2000
28
issue. Prior to December 31, 1999, we completed a comprehensive review of our
computer systems to identify the systems that could be affected by the Year 2000
issue and developed and implemented a plan to mitigate the risk of any problems.
Our remediation plan included: (i) creating a Year 2000 awareness program to
educate employees; (ii) compiling an inventory of all systems; (iii) developing
system test plans as appropriate; (iv) completing the testing and remediation as
required for both information and non-information technology systems; and (v)
developing contingency plans to minimize the impact of a Year 2000 related
failure caused either internally or externally. Additionally, we surveyed our
business counterparties periodically regarding their Year 2000 conversion and
contingency plans. In total, we spent approximately $1.1 million for
remediation purposes, which primarily consisted of purchasing hardware and
software upgrades. We also incurred internal staff costs and other expenses,
which were immaterial.
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, five 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 "grandfathered" air
emissions sources within the State of Texas. A "grandfathered" air emissions
source is one that does not need a state operating permit because it was
constructed prior to 1971. We operate a number of these sources within the State
of Texas, including portions of our Midkiff plant and many of our compressors.
The recommendations proposed by the committee would create a voluntary
permitting program for grandfathered sources, including incentives to
participate, like the ability to operate these sources in a flexible manner. It
is not clear which of the committee's recommendations, if any, that the
Commission will implement and it is not possible to assess the potential effect
on us until final regulations are promulgated.
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 $2.6 million for the year ended
December 31, 1999, including approximately $500,000 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.
29
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements
Western Gas Resources, Inc.'s Consolidated Financial Statements as of December
31, 1999 and 1998 and for each of the three years in the period ended December
31, 1999:
Page
----
Report of Management....................................................... 28
Report of Independent Accountants.......................................... 29
Consolidated Balance Sheets................................................ 30
Consolidated Statement of Cash Flows....................................... 31
Consolidated Statement of Operations....................................... 32
Consolidated Statement of Changes in Stockholders' Equity.................. 33
Notes to Consolidated Financial Statements................................. 34
30
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)
31
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, 1999 and 1998,
and the results of their cash flows and their operations for each of the three
years in the period ended December 31, 1999, in conformity with accounting
principles generally accepted in the United States. 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 which require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the opinion expressed
above.
PricewaterhouseCoopers LLP
Denver, Colorado
March 13, 2000
32
WESTERN GAS RESOURCES, INC.
CONSOLIDATED BALANCE SHEET
(000s, except share data)
December 31,
-----------------------
ASSETS 1999 1998
------ ---------- ----------
Current assets:
Cash and cash equivalents.................................................... $ 14,062 $ 4,400
Trade accounts receivable, net............................................... 196,739 233,574
Product inventory............................................................ 35,228 46,207
Parts inventory.............................................................. 10,318 10,153
Assets held for sale......................................................... 7,237 -
Other........................................................................ 9,571 2,951
---------- ----------
Total current assets....................................................... 273,155 297,285
---------- ----------
Property and equipment:
Gas gathering, processing, storage and transmission.......................... 808,274 952,531
Oil and gas properties and equipment......................................... 104,137 111,602
Construction in progress..................................................... 39,987 87,943
---------- ----------
952,398 1,152,076
Less: Accumulated depreciation, depletion and amortization................... (260,081) (305,589)
---------- ----------
Total property and equipment, net.......................................... 692,317 846,487
---------- ----------
Other assets:
Gas purchase contracts (net of accumulated amortization of $31,273 and
$29,978, respectively)..................................................... 36,883 41,263
Other........................................................................ 47,131 34,342
---------- ----------
Total other assets........................................................... 84,014 75,605
---------- ----------
Total assets................................................................... $1,049,486 $1,219,377
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
Current liabilities:
Accounts payable............................................................. $ 240,235 $ 245,315
Accrued expenses............................................................. 41,075 31,727
Dividends payable............................................................ 4,218 4,217
---------- ----------
Total current liabilities.................................................. 285,528 281,259
Long-term debt................................................................. 378,250 504,881
Deferred income taxes payable, net............................................. 35,965 48,021
---------- ----------
Total liabilities.............................................................. 699,743 834,161
---------- ----------
Commitments and contingent liabilities......................................... - -
Stockholders' equity:
Preferred Stock; 10,000,000 shares authorized:
$2.28 cumulative preferred stock, par value $.10; 1,400,000 shares issued
($35,000,000 aggregate liquidation preference)........................... 140 140
$2.625 cumulative convertible preferred stock, par value $.10; 2,760,000
issued ($138,000,000 aggregate liquidation preference).................... 276 276
Common stock, par value $.10; 100,000,000 shares authorized; 32,186,747 and
32,173,009 shares issued, respectively..................................... 3,220 3,217
Treasury stock, at cost; 25,016 shares in treasury........................... (788) (788)
Additional paid-in capital................................................... 397,522 397,344
Retained earnings............................................................ (51,064) (17,075)
Accumulated other comprehensive income....................................... 1,321 3,053
Notes receivable from key employees secured by common stock.................. (884) (951)
---------- ----------
Total stockholders' equity................................................. 349,743 385,216
---------- ----------
Total liabilities and stockholders' equity..................................... $1,049,486 $1,219,377
========== ==========
The accompanying notes are an integral part of the consolidated financial
statements.
33
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(000s)
Year Ended December 31,
---------------------------------------
1999 1998 1997
----------- ----------- -----------
Reconciliation of net income to net cash provided by operating activities:
Net income (loss)........................................................... $ (17,124) $ (67,205) $ 1,487
Add income items that do not affect cash:
Depreciation, depletion and amortization................................... 50,981 59,346 59,248
Deferred income taxes...................................................... (11,428) (32,722) 465
Distributions in excess of (less than) equity income, net.................. (987) 963 1,764
(Gain) Loss on the sale of property and equipment.......................... 29,802 (16,478) (4,715)
Impairment of property and equipment....................................... 1,158 108,447 34,615
Other non-cash items, net.................................................. (1,080) 2,595 3,284
----------- ----------- -----------
51,322 54,946 96,148
----------- ----------- -----------
Adjustments to working capital to arrive at net cash provided by
operating activities:
Decrease in trade accounts receivable...................................... 36,567 25,317 79,963
(Increase) decrease in product inventory................................... 10,963 (29,810) 7,480
Increase in parts inventory................................................ (165) (748) (6,806)
(Increase) decrease in other current assets................................ (6,620) (587) (1,027)
Decrease in other assets and liabilities, net............................. 350 257 257
(Decrease) in accounts payable............................................. (4,960) (81,381) (59,572)
(Decrease) increase in accrued expenses.................................... 7,727 (3,564) (1,688)
----------- ----------- -----------
Total adjustments......................................................... 43,862 (90,516) 18,607
----------- ----------- -----------
Net cash provided by (used in) operating activities......................... 95,184 (35,570) 114,755
----------- ----------- -----------
Cash flows from investing activities:
Purchases of property and equipment, including acquisitions................ (80,089) (104,171) (196,293)
Proceeds from the disposition of property and equipment.................... 148,685 75,286 20,034
Contributions to unconsolidated affiliates................................. (1,400) (1,045) (2,608)
Distribution from unconsolidated affiliates................................ 88 3,489 -
----------- ----------- -----------
Net cash provided by (used in) investing activities......................... 67,284 (26,441) (178,867)
----------- ----------- -----------
Cash flows from financing activities:
Net proceeds from exercise of common stock options......................... 158 23 239
Proceeds from issuance of long-term debt................................... 155,000 - -
Payments on long-term debt................................................. (92,380) (15,476) (94,643)
Borrowings under revolving credit facility................................. 2,115,250 3,230,400 1,894,950
Payments on revolving credit facility...................................... (2,304,500) (3,151,400) (1,738,450)
Debt issue costs paid...................................................... (9,469) (44) (847)
Dividends paid............................................................. (16,865) (16,869) (16,864)
----------- ----------- -----------
Net cash provided by (used in) financing activities......................... (152,806) 46,634 44,385
----------- ----------- -----------
Net increase (decrease) in cash and cash equivalents........................ 9,662 (15,377) (19,727)
Cash and cash equivalents at beginning of year.............................. 4,400 19,777 39,504
----------- ----------- -----------
Cash and cash equivalents at end of year.................................... $ 14,062 $ 4,400 $ 19,777
=========== =========== ===========
The accompanying notes are an integral part of the consolidated financial
statements.
34
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
(000s, except share and per share amounts)
Year Ended December 31,
---------------------------------------
1999 1998 1997
----------- ----------- -----------
Revenues:
Sale of gas............................................................. $ 1,501,066 $ 1,611,521 $ 1,657,479
Sale of natural gas liquids............................................. 346,819 449,696 611,969
Sale of electric power.................................................. - 20 59,477
Processing, transportation and storage revenue.......................... 48,994 44,743 40,906
Other, net.............................................................. 13,845 11,108 10,714
----------- ----------- -----------
Total revenues........................................................ 1,910,724 2,117,088 2,380,545
----------- ----------- -----------
Costs and expenses:
Product purchases....................................................... 1,715,839 1,914,303 2,146,430
Plant operating expense................................................. 67,419 85,353 78,113
Oil and gas exploration and production costs............................ 9,196 7,996 7,714
Depreciation, depletion and amortization................................ 50,981 59,346 59,248
Selling and administrative expense...................................... 28,357 30,128 29,446
(Gain) loss on sale of assets........................................... 29,802 (16,478) (4,715)
Interest expense........................................................ 33,156 33,616 27,474
Loss on the impairment of property and equipment........................ 1,158 108,447 34,615
----------- ----------- -----------
Total costs and expenses.............................................. 1,935,908 2,222,711 2,378,325
----------- ----------- -----------
Income (loss) before income taxes........................................ (25,184) (105,623) 2,220
Provision (benefit) for income taxes:
Current................................................................. 2,261 (5,696) 268
Deferred................................................................ (11,428) (32,722) 465
----------- ----------- -----------
Total provision (benefit) for income taxes............................ (9,167) (38,418) 733
----------- ----------- -----------
Income (loss) before extraordinary items................................. (16,017) (67,205) 1,487
Extraordinary charge for early extinguishment of debt,
net of tax benefit of $628,000........................................ (1,107) - -
----------- ----------- -----------
Net income (loss)........................................................ $ (17,124) $ (67,205) $ 1,487
----------- ----------- -----------
Preferred stock requirements............................................. (10,436) (10,439) (10,439)
----------- ----------- -----------
Loss attributable to common stock........................................ $ (27,563) $ (77,644) $ (8,952)
=========== =========== ===========
Loss per share of common stock........................................... $ (.86) $ (2.42) $ (.28)
=========== =========== ===========
Weighted average shares of common stock outstanding...................... 32,150,887 32,147,354 32,134,011
=========== =========== ===========
Loss per share of common stock - assuming dilution....................... $ (.86) $ (2.42) $ (.28)
=========== =========== ===========
Weighted average shares of common stock outstanding - assuming dilution.. 32,150,887 32,147,354 32,137,803
=========== =========== ===========
The accompanying notes are an integral part of the consolidated financial
statements.
35
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
(000s, except share amounts)
Shares of $2.625 $2.625
$2.28 Cumulative Shares $2.28 Cumulative
Cumulative Convertible Shares of Common Cumulative Convertible
Preferred Preferred of Common Stock Preferred Preferred Common Treasury
Stock Stock Stock in Treasury Stock Stock Stock Stock
---------- ----------- ---------- ----------- ---------- ----------- ------ --------
Balance at December 31, 1996............ 1,400,000 2,760,000 32,109,135 25,016 $ 140 $ 276 $3,213 $ (788)
Net income, 1997........................ - - - - - - - -
Stock options exercised................. - - 37,302 - - - 4 -
Tax benefit related to stock options.... - - - - - - - -
Loans forgiven.......................... - - - - - - - -
Dividends declared on common stock...... - - - - - - - -
Dividends declared on $2.28 cumulative
preferred stock........................ - - - - - - - -
Dividends declared on $2.625 cumulative
convertible preferred stock............ - - - - - - - -
---------- ----------- ---------- ----------- ---------- ----------- ------ --------
Balance at December 31, 1997............ 1,400,000 2,760,000 32,146,437 25,016 140 276 3,217 (788)
Net income, 1998........................ - - - - - - - -
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............ - - - - - - - -
Translation adjustments................. - - - - - - - -
---------- ----------- ---------- ----------- ---------- ----------- ------ --------
Balance at December 31, 1998............ 1,400,000 2,760,000 32,147,993 25,016 140 276 3,217 (788)
Net income, 1999........................ - - - - - - - -
Stock options exercised................. - - 13,738 - - - 3 -
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............ - - - - - - - -
Translation adjustments................. - - - - - - - -
---------- ----------- ---------- ----------- ---------- ----------- ------ --------
Balance at December 31, 1999............ 1,400,000 2,760,000 32,161,731 25,016 $ 140 $ 276 $3,220 $ (788)
========== =========== ========== =========== ========== =========== ====== ========
Cumulative
Accumulated Notes Total
Additional Retained Other Receivable Stock-
Paid-In (Deficit) Comprehensive from Key holders'
Capital Earnings Income Employees Equity
---------- ----------- ------------- ---------- ---------
Balance at December 31, 1996............ $ 397,061 $ 82,378 $ - $ (1,813) $ 480,467
Net income, 1997........................ - 1,487 - - 1,487
Stock options exercised................. 260 - - (25) 239
Tax benefit related to
stock options.......................... - - 2,233 - 2,233
Loans forgiven.......................... - - - 552 552
Dividends declared on common stock...... - (6,427) - (6,427)
Dividends declared on $2.28 cumulative
preferred stock........................ - (3,194) - - (3,194)
Dividends declared on $2.625 cumulative
convertible preferred stock............ - (7,245) - - (7,245)
---------- ----------- ------------- ---------- ---------
Balance at December 31, 1997............ 397,321 66,999 2,233 (1,286) 468,112
Net income, 1998........................ - (67,205) - - (67,205)
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)
Translation adjustments................. - - 820 - 820
---------- ----------- ------------- ---------- ---------
Balance at December 31, 1998............ 397,344 (17,075) 3,053 (951) 385,216
Net income, 1999........................ - (17,124) - - (17,124)
Stock options exercised................. 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)
Translation adjustments................. - - (1,732) - (1,732)
---------- ----------- ------------- ---------- ---------
Balance at December 31, 1999............ $ 397,522 $ (51,064) $ 1,321 $ (884) $ 349,743
========== =========== ============= ========== =========
The accompanying notes are an integral part of the consolidated financial
statements.
36
NOTE 1 - NATURE OF ORGANIZATION
- -------------------------------
Western Gas Resources, Inc. (the "Company") gathers, processes, treats, develops
and produces, transports and markets natural gas and NGLs. 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 designs, constructs,
owns and operates natural gas gathering systems and processing and treating
facilities in order to provide its customers with a broad range of services from
the wellhead to the sales delivery point.
Western Gas Resources, Inc. was formed in October 1989 to acquire a majority
interest in Western Gas Processors, Ltd. (the "Partnership") and to assume the
duties of WGP Company, the general partner of the Partnership. The Partnership
was a Colorado limited partnership formed in 1977 to engage in the gathering and
processing of natural gas. The reorganization was accomplished in December 1989
through an exchange for common stock of partnership units held by the former
general partners of WGP Company and an initial public offering of Western Gas
Resources, Inc. Common Stock. On May 1, 1991, a further restructuring
("Restructuring") of the Partnership and Western Gas Resources, Inc. (together
with its predecessor, WGP Company, collectively, the "Company") was approved by
a vote of the security holders. The combinations were reorganizations of
entities under common control and were accounted for at historical cost in a
manner similar to poolings of interests.
The Company has completed three public offerings of Common Stock. In December
1989, the Company issued 3,527,500 shares of Common Stock at a public offering
price of $11.50. In November 1991, the Company issued 4,115,000 shares of
Common Stock at a public offering price of $18.375 per share. In November 1996,
the Company issued 6,325,000 shares of Common Stock at a public offering price
of $16.25 per share. The net proceeds to the Company from the November 1996
public offering of Common Stock of $96.4 million were primarily used to reduce
indebtedness under the Revolving Credit Facility.
The Company has also issued preferred stock in a private transaction and has
completed two public offerings of preferred stock. In October 1991, the Company
issued 400,000 shares of 7.25% Cumulative Senior Perpetual Convertible Preferred
Stock ("7.25% Preferred Stock") with a liquidation preference of $100 per share
to an institutional investor. In May 1995, the Company redeemed all of the
issued and outstanding shares of its 7.25% Preferred Stock pursuant to the
provisions of its Certificate of Designation relating to such preferred stock,
at an aggregate redemption price of approximately $42.0 million, including a
redemption premium of $2.0 million. In November 1992, the Company issued
1,400,000 shares of $2.28 Cumulative Preferred Stock with a liquidation
preference of $25 per share, at a public offering price of $25 per share,
redeemable at the Company's option on or after November 15, 1997. In February
1994, the Company issued 2,760,000 shares of $2.625 Cumulative Convertible
Preferred Stock with a liquidation preference of $50 per share, at a public
offering price of $50 per share, redeemable at the Company's option on or after
February 16, 1997 and convertible at the option of the holder into Common Stock
at a conversion price of $39.75.
Significant Business Acquisitions, Dispositions and Projects
Coal Bed Methane
The Company continues to expand its Powder River basin coal bed methane natural
gas gathering system and developing its own coal seam gas reserves in Wyoming.
During the years ended December 31, 1999, 1998 and 1997, the Company expended
approximately $51.4 million, $46.7 million and $32.2 million, respectively, on
this project. On October 30, 1997, the Company sold a 50% undivided interest in
its Powder River basin coal bed methane gas operations. The purchase price was
$17.9 million, resulting in a pre-tax gain of $4.7 million.
In December 1998, the Company joined with other industry participants to form
the Fort Union Gas Gathering, L.L.C., to construct a 106-mile, 24-inch gathering
pipeline and treater to gather and treat natural gas in the Powder River basin
in northeast Wyoming. The Company owns an approximate 13% interest in the L.L.C.
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
37
MMcf/D of capacity for $.14 per Mcf on Fort Union beginning in December 1999.
Southwest Wyoming
The Company's facilities in southwest Wyoming are comprised of the Granger
facility and a 72% ownership interest in the Lincoln Road facility (collectively
the "Granger Complex"). The Company began to expand its gas gathering and
exploration and production activities in southwest Wyoming during 1997. The
expansion in this area is primarily intended to develop acreage to replace
declines in reserves and generate additional volumes for gathering and
processing at its facilities. During the years ended December 31, 1999 and 1998,
the Company expended approximately $13.2 million and $16.0 million,
respectively, on this project. 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 1997, the Company granted an option to an affiliate of a producer behind the
Granger Complex to purchase up to 50% of the Granger Complex. In conjunction
with this agreement, in February 1998, the Company received a $1 million non-
refundable option payment. The option to acquire an interest in these
facilities expired in the fourth quarter of 1998.
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.
This sale closed in January 2000. This transaction resulted in an approximate
pre-tax loss (subject to final accounting adjustment) of $7.3 million, which was
accrued 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.
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. In April 1999,
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 has entered into a long-term agreement with the
purchaser for 3 Bcf of storage capacity at market rates.
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 the receipt of large acreage dedications in
this area, the Company constructed the Bethel treating facility for a total cost
of approximately $102.8 million with a throughput capacity of 350 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. As a result, in 1999, the Bethel treating facility averaged
gas throughput of approximately 98 MMcf/D. Due to the unexpected poor drilling
results and reductions in the producers' drilling budgets, the number of rigs
actively drilling for Pinnacle Reefs has decreased from 18 in July 1998 to three
in December 1999.
38
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.
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 ("Redman Smackover"). The combined sales price was $55.8 million.
The proceeds from these sales were used to repay a portion of the balances
outstanding under the Revolving Credit Facility. After the accrual of certain
related expenses, the Company recognized a pre-tax gain of approximately $1.6
million, during the fourth quarter of 1998.
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.
Subsequent Events
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 will recognize a pre-tax gain on the
sale, subject to final accounting adjustment, of approximately $5.5 million in
the first quarter of 2000.
In February 2000, the Company acquired the remaining 50% interest in the Westana
Gathering Company for a gross purchase price of $10.8 million. This transaction
is effective January 1, 2000 and is subject to final accounting adjustment.
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
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 $32.8 million and $42.8 million of gas and $2.9 million and
$3.4 million of NGLs at December 31, 1999 and 1998, respectively. During the
year ended December 31, 1998, the Company recorded a lower of cost or market
write-down of NGL inventories of $826,000.
39
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 as incurred.
Upon surrender of undeveloped properties, the original cost is charged against
income. Producing properties and related equipment are depleted and depreciated
by the units-of-production method based on estimated proved reserves for
producing properties and proved developed reserves for lease and well equipment.
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."
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, 1999 and 1998 were $(1.7) million and $820,000, respectively.
The adjustment for the year ended December 31, 1997 was not material.
Revenue Recognition
Revenue for sales or services is recognized at the time the gas, NGLs or
electric power is delivered or at the time the service is performed.
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 $(1.7) million and
$820,000 for the years ended December 31, 1999 and 1998 and tax benefits related
to stock options of $2.2 million for the year ended December 31, 1997 are
separately reported on the Consolidated Statement of Changes in Stockholders'
Equity.
Gas and NGL Hedges
Gains and losses on hedges of product inventory are included in the carrying
amount of the inventory and are ultimately recognized in gas and NGL sales when
the related inventory is sold. Gains and losses related to qualifying hedges,
as defined by SFAS No. 80, "Accounting for Futures Contracts," of firm
commitments or anticipated transactions (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
40
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 1999, 1998 and 1997.
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, $108.5 million and $34.6
million in accordance with SFAS No. 121 during the years ended December 31,
1999, 1998 and 1997, respectively.
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, 1999, 1998 and 1997, respectively. Common stock options, which are
potential common shares, had a dilutive effect on earnings per share and
increased the weighted average shares of common stock outstanding by 3,792
shares for the year ended December 31, 1997. The common stock options 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, 1999 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 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. At December 31, 1999, the Company believes
it had no significant concentrations of credit risk.
One customer accounted for approximately 19% of the Company's consolidated
revenues from the sale of NGLs, or 3% of total consolidated revenue, for the
year ended December 31, 1999. This customer is a large integrated utility.
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
41
Interest paid was $34.1 million, $36.1 million and $33.1 million, respectively,
for the years ended December 31, 1999, 1998 and 1997. Capitalized interest
associated with construction of new projects was $2.0 million, $2.5 million and
$5.1 million, respectively, for the years ended December 31, 1999, 1998 and
1997. Income taxes paid or (refunded) were $(2.9) million, $0 and $2.6 million,
respectively, for the years ended December 31, 1999, 1998 and 1997.
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. In September 1997, the Company recorded a credit of
$2.2 million to additional paid-in capital to reflect such difference associated
with the Company's $5.40 Stock Option Plan.
Use of Estimates and Significant Risks
The preparation of consolidated financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the amounts reported in these financial statements
and accompanying notes. The more significant areas requiring the use of
estimates relate to oil and gas reserves, fair value of financial instruments,
future 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.
Accounting for Derivative Instruments and Hedging Activities
In June 1998, the Financial Accounting Standards Board 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,
the Company will be required to recognize 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. The Company has not yet determined the impact that
the adoption of SFAS No. 133 will have on its earnings or financial position.
Reclassifications
Certain prior years' amounts in the consolidated financial statements and
related notes have been reclassified to conform to the presentation used in
1999.
NOTE 3 - RELATED PARTIES
- ------------------------
42
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") and Westana Gathering Company ("Westana").
Williston Gas Company was dissolved effective December 31, 1998 and the Company
purchased the remaining 50% interest in Westana in February 2000. In addition,
for the year ended December 31, 1997, the Company also had a 50% ownership
interest in Redman Smackover. This interest was sold effective July 1, 1998. The
Company acted as operator for Williston and Westana. The Company also had a 49%
interest in the Sandia Energy Resources Joint Venture ("Sandia"), which was
dissolved in 1999. The Company's share of equity income or loss in these
ventures is reflected in other net revenue. All transactions entered into by
the Company with its related parties 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 charged a monthly overhead fee to cover such
services.
The Company performed various operational and administrative functions for
Westana and charged a monthly overhead fee to cover such services. The Company
recorded receivable and payable balances at the end of each accounting period
related to transactions with Westana. At December 31, 1999, the Company's
investment in Westana was $28.9 million.
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 the joint venture.
The following table summarizes account balances reflected in the financial
statements (000s):
As of or for the Year Ended December 31,
----------------------------------------
1999 1998 1997
------------ ------------ ------------
Trade accounts receivable.. $ 4,895 $ 3,794 $ 4,295
============ ============ ============
Accounts payable........... 3,915 9,474 7,246
============ ============ ============
Sales of gas and NGLs...... 6,635 31,319 19,504
============ ============ ============
Processing revenue......... 225 192 336
============ ============ ============
Product purchases.......... 51,676 58,899 59,082
============ ============ ============
Administrative expense..... $ 450 $ 483 $ 421
============ ============ ============
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.
The loan and accrued interest will be forgiven if the employee has been
continuously employed by the Company for periods specified under the agreements
and Board of Directors' resolutions. As of December 31, 1999 and 1998, loans
related to 75,000 and 81,250 shares of Common Stock, respectively, totaling
$803,000 and $870,000, respectively, were outstanding to certain current and
past employees under these programs. The loans are secured by a portion of the
Common Stock issued upon exercise of the options and are accounted for as a
reduction of stockholders' equity. During 1999 and 1998, the Board of Directors
approved the forgiveness of loans to certain individuals totaling approximately
$67,000 and $335,000, respectively, in connection with these plans.
NOTE 4 - COMMODITY RISK MANAGEMENT
- ----------------------------------
Risk Management Activities
43
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.
The Company has hedged a portion of its equity volumes of gas and NGLs in 2000,
at pricing levels approximating its 2000 operating budget. The Company's equity
hedging strategy establishes a minimum price to the Company while allowing
varying levels of market participation above the minimum. As of February 8,
2000, the Company has hedged approximately 42%, or 30,000 MMBtu/day, of its
anticipated equity gas for 2000 at a weighted average NYMEX equivalent price of
$2.22 per MMBtu and an additional 31%, or 22,000 MMBtu/day, of collars with a
minimum $2.10 per MMBtu and a maximum $2.44 per MMBtu NYMEX equivalent price.
The Company has hedged approximately 26%, or 25,000 Bbl per month of its
anticipated equity natural gasoline, condensate and crude oil for 2000 using a
collar with a minimum $15.00 per Bbl and maximum $17.00 per Bbl NYMEX crude oil
monthly average price. The Company has also hedged approximately 46%, or 195,000
Bbl per month, of its anticipated equity production of NGLs for 2000 with a
minimum weighted average Mt. Belvieu price composite of $0.27 per gallon.
Additionally, the Company has hedged approximately 27%, or 345,000 Bbls of first
quarter NGLs at a weighted average Mt. Belvieu price of $0.52 per gallon.
At December 31, 1999 the Company had $600,000 of unrecognized gains in inventory
that will be recognized primarily during the first quarter of 2000 which may
be offset by margins from the Company's related forward fixed price hedges
and physical sales. At December 31, 1999 the Company had unrecognized net losses
of $925,000 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
44
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, 1999 and 1998 were not
material.
Natural Gas Derivative Market Risk
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. As of December 31, 1998, the Company held a
notional quantity of approximately 370 Bcf of natural gas futures, swaps and
options extending from January 1999 to December 2000 with a weighted average
duration of approximately four months. This was comprised of approximately 178
Bcf of long positions and 192 Bcf of short positions in such instruments.
Crude Oil and NGL Derivative Market Risk
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 111,000 MGal of long positions and 13,000
MGal of short positions in such instruments. As of December 31, 1998, the
Company held a notional quantity of approximately 177,000 MGal of NGL futures,
swaps and options extending from January 1999 to December 1999 with a weighted
average duration of approximately six months. This was comprised of
approximately 129,000 MGal of long positions and 48,000 MGal of short positions
in such instruments.
As of December 31, 1999, the Company had purchased 25,000 barrels per month of
NYMEX monthly average settlement $15.00 per barrel puts and sold 25,000 barrels
per month of NYMEX monthly average settlement $17.00 calls to hedge a portion of
the Company's equity production of natural gasoline, condensates and crude oil.
The Company held no crude oil futures, swaps or options for settlement beyond
2000.
As of December 31, 1999, the Company had purchased 125,000 barrels per month of
OPIS Mt. Belvieu monthly average settlement $0.300 per gallon puts to hedge a
portion of the Company's equity production of propane and butanes for 2000.
As of December 31, 1999, the Company had purchased 70,000 barrels per month of
OPIS Mt. Belvieu monthly average settlement $0.220 per gallon of purity ethane
puts to hedge a portion of the Company's equity production of ethane for 2000.
As of December 31, 1999, the Company held no NGL futures, swaps or options for
settlement beyond 2000.
As of December 31, 1999, the estimated fair value of the aforementioned crude
oil and NGL options held by the Company was approximately $(194,000).
Foreign Currency Derivative Market Risk
45
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, 1999, the net notional value of such
contracts was approximately $7.5 million in Canadian dollars, which approximates
its fair market value. As of December 31, 1998, the net notional value of such
contracts was approximately $11.0 million in Canadian dollars, which
approximated its fair market value.
NOTE 5 - DEBT
- -------------
The following summarizes the Company's consolidated debt at the dates indicated
(000s):
December 31,
------------------
1999 1998
-------- --------
Master Shelf and Senior Notes............ $332,000 $269,381
Variable rate Revolving Credit Facility.. 46,250 235,500
-------- --------
Total long-term debt.................... $378,250 $504,881
======== ========
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, 1999,
$46.3 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 its debt to capitalization ratio and range from .75% to 2.00%.
At December 31, 1999, the interest rate payable on the facility was 7.9%. 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 ratio of
EBITDA, excluding certain non-recurring items, to interest and dividends on
preferred stock as of the end of any fiscal quarter, for the four preceding
fiscal quarters, of not less than 1.35 to 1.0 and increasing to 3.25 to 1.0 by
December 31, 2002. This facility is guaranteed and secured via a pledge of the
stock of certain of its subsidiaries. The Company generally utilizes excess
daily funds to reduce any outstanding balances on the Revolving Credit Facility
and associated interest expense, and intends to continue such practice.
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 31,1999 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 April 1999, effective January 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 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 40% through March 2002 and 35%
thereafter. This amendment also requires an EBITDA to interest ratio of not less
than 1.75 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
46
than 1.75 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, the Company is prohibited from declaring or paying dividends that in
the aggregate exceed the sum of $50 million plus 50% of consolidated net income
earned after June 30, 1995, or minus 100% of a net loss, plus the aggregate net
cash proceeds received after June 30, 1995 from the sale of any stock. At
December 31, 1999, approximately $25.6 million was available under this
limitation. The Company financed the $8.3 million payment made in October 1999
with amounts available under the Revolving Credit Facility. Borrowings under the
Master Shelf Agreement are guaranteed and secured via a pledge of the stock of
certain of its subsidiaries.
In June 1999, the Company prepaid approximately $33.3 million of notes
outstanding under the Master Shelf Agreement with proceeds from the offering of
the Subordinated Notes.
1995 Senior Notes. In 1995, the Company sold $42 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 million of the principal
amount outstanding on the 1995 Senior Notes at par. These payments were financed
by a portion of the $37 million Bridge Loan described below and by amounts
available under the Revolving Credit Facility. The remaining principal amount
outstanding of $27 million is due in a single payment in December 2005. The 1995
Senior Notes are guaranteed and secured via a pledge of the stock of certain of
its subsidiaries. This facility contains covenants similar to the Master Shelf
Agreement. In the second quarter of 1999 and in January 2000, the Company posted
letters of credit for a total of approximately $11.8 million for the benefit of
the holders of the 1995 Senior Notes.
The Company is currently paying an annual fee of not more than .65% on the
amounts outstanding on the Master Shelf Agreement and the 1995 Senior Notes.
This fee will continue until the Company receives an implied investment grade
rating on its senior secured debt. This fee is not assessed on the portion of
the 1995 Senior Notes for which letters of credit are posted.
1993 Senior Notes. In 1993, the Company sold $50 million of 7.65% Senior
Notes, the 1993 Senior Notes, to a group of insurance companies. Scheduled
annual principal payments of $7.1 million on the 1993 Senior Notes were made on
April 30 of 1997 and 1998. In February 1999, the Company prepaid $33.5 million
of the total principal amounts outstanding of $35.6 million at par. These
payments were financed by a portion of the $37 million Bridge Loan. The Company
prepaid the remaining outstanding principal of $2.1 million in April 1999 with
amounts available under the Revolving Credit Facility.
In connection with the repayments on the Master Shelf Agreement, the 1995 Senior
Notes and the 1993 Senior Notes, the Company incurred approximately $1.8 million
of pre-tax yield maintenance and other charges. These charges are reflected as
an extraordinary loss from early extinguishment of long-term debt in the second
quarter of 1999.
Bridge Loan. In February 1999, in order to finance prepayments of amounts
outstanding on the 1993 and 1995 Senior Notes, the Company entered into a Bridge
Loan agreement in the amount of $37 million with its agent bank. This facility
was paid in full in April 1999 with proceeds from the sale of the Katy facility.
Senior Subordinated Notes. In June 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. 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. In November 1999, the
Company exchanged the privately placed notes for registered publicly tradable
notes under the same terms and conditions. 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, 1999. Taking into account all the covenants
contained in these agreements, the Company had approximately $110 million of
available borrowing capacity at December 31, 1999. In the second quarter of
1999, the Company amended its various financing facilities providing for
financial flexibility and covenant modifications and issued the Subordinated
Notes. These amendments were needed given the depressed commodity pricing
experienced in the industry in general at that time and the disappointing
results at its Bethel Treating facility. The Company can provide no assurance
that further amendments or waivers can be obtained in the future, if necessary,
or that the terms would be favorable to it. To strengthen its credit ratings and
to reduce its overall debt outstanding, the Company will continue to dispose of
non-strategic assets and investigate alternative financing sources including the
issuance of public debt, project-financing, joint ventures
47
and operating leases.
Approximate future maturities of long-term debt in the year indicated are as
follows at December 31, 1999 (000s):
2000............................................ $ 0
2001............................................ 33,333
2002............................................ 8,333
2003............................................ 43,334
2004............................................ 81,250
Thereafter...................................... 212,000
--------
Total......................................... $ 378,250
========
NOTE 6 - FINANCIAL INSTRUMENTS
- ------------------------------
The estimated fair values of the Company's financial instruments have been
determined by the Company using available market information and valuation
methodologies. Considerable judgment is required to develop the estimates of
fair value; thus, the estimates provided herein are not necessarily indicative
of the amount that the Company could realize upon the sale or refinancing of
such financial instruments.
December 31, 1999 December 31, 1998
------------------- -------------------
Carrying Fair Carrying Fair
Value Value Value Value
--------- -------- --------- --------
(000s) (000s)
Cash and cash equivalents.. $ 14,062 $ 14,062 $ 4,400 $ 4,400
Trade accounts receivable.. 210,628 210,628 233,574 233,574
Accounts payable........... 240,235 240,235 245,315 245,315
Long-term debt............. 378,250 367,496 504,881 503,001
Risk management contracts.. $ - $ (1,668) $ - $ 2,281
The following methods and assumptions were used by the Company in estimating the
fair value of its financial instruments:
Cash and cash equivalents, trade accounts receivable and accounts payable
Due to the short-term nature of these instruments, the carrying value
approximates the fair value.
Long-term debt
The Company's long-term debt was primarily comprised of fixed rate facilities;
for this portion, fair market value was estimated using discounted cash flows
based upon the Company's current borrowing rates for debt with similar
maturities. The remaining portion of the long-term debt was borrowed on a
revolving basis which accrues interest at current rates; as a result, carrying
value approximates fair value of the outstanding debt.
Risk Management Contracts
Fair value represents the amount at which the instrument could be exchanged in a
current arms-length transaction.
NOTE 7 - INCOME TAXES
- ---------------------
48
The provision (benefit) for income taxes for the years ended December 31, 1999,
1998 and 1997 before the tax effect of the extraordinary item is comprised of
(000s):
1999 1998 1997
-------- -------- -----
Current:
Federal............................. $ 2,261 $ (5,696) $ 268
State............................... - - -
-------- -------- -----
Total Current....................... 2,261 (5,696) 268
-------- -------- -----
Deferred:
Federal............................. (11,004) (31,272) 448
State............................... (424) (1,450) 17
-------- -------- -----
Total Deferred...................... (11,428) (32,722) 465
-------- -------- -----
Total tax provision (benefit).. $ (9,167) $(38,418) $ 733
======== ======== =====
The tax benefit allocated to the extraordinary charge was $628,000.
Temporary differences and carry-forwards which give rise to the deferred tax
liabilities (assets) at December 31, 1999 and 1998 net of the tax effect of
the extraordinary item are as follows (000s):
1999 1998
--------- ---------
Property and equipment......................................... $108,357 $133,054
Differences between the book and tax basis of acquired assets.. 13,439 14,386
-------- --------
Total deferred income tax liabilities......................... 121,796 147,440
-------- --------
Alternative Minimum Tax (AMT) credit carry-forwards.......... (23,389) (21,128)
Net Operating Loss (NOL) carry-forwards...................... (62,442) (78,291)
-------- --------
Total deferred income tax assets.............................. (85,831) (99,419)
-------- --------
Net deferred income taxes..................................... $ 35,965 $ 48,021
======== ========
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 the extraordinary item for the years ended December 31, 1999, 1998
and 1997 are summarized as follows (000s):
49
1999 % 1998 % 1997 %
-------- ----- --------- ----- ------ -----
Income tax (benefit) before effect of
extraordinary item at statutory rate......... $(8,814) 35.0 $(36,968) 35.0 $ 777 35.0
State income taxes (benefit), net of federal
benefit...................................... (353) 1.4 (1,450) 1.4 31 1.4
Other......................................... - - - - (75) (3.4)
------- ---- -------- ---- ----- ----
Total........................................ $(9,167) 36.4 $(38,418) 36.4 $ 733 33.0
======= ==== ======== ==== ===== ====
At December 31, 1999 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 $171.8 million and $23.4 million, respectively. These
carry-forwards expire as follows (000s):
Expiration Dates NOL AMT
-------------------------------- -------- -------
2008............................ $ 11,269 $ -
2009............................ 7,122 -
2010............................ 56,487 -
2011............................ 15,247 -
2012............................ 38,990 -
2018............................ 42,690 -
No expiration................... - 23,389
-------- -------
Total........................ $171,805 $23,389
======== =======
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.
NOTE 8 - COMMITMENTS AND CONTINGENT LIABILITIES
- -----------------------------------------------
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.
McMurry Oil Company and certain other producers (collectively, "McMurry") filed
suit against TBI Exploration, Inc. ("TBI"), Mountain Gas Resources, Inc., our
wholly-owned subsidiary ("Mountain Gas"), and Wildhorse Energy Partners, LLC
("Wildhorse"). The central dispute in this case concerns the ownership, nature
and extent of a call on certain gas and the rights to match offers for gathering
and/or purchasing gas (collectively the "Preferential Rights"). In November
1998, the court granted summary judgment in favor of McMurry as to the ownership
of the Preferential Rights. In early 1999, McMurry, TBI and Wildhorse settled
their claims and crossclaims and as a result TBI and Wildhorse were dismissed
from the case. Trial on the liability phase of the litigation between McMurry
and Mountain Gas was held in May 1999 and judgment was rendered against Mountain
Gas in June 1999, assessing liability for intentional interference of business
expectancies and opportunities and a finding that such interference caused
McMurry to forego or delay entry into these opportunities and further, that
Mountain Gas' assertion of ownership of Preferential Rights were false and
thereby disparaged McMurry's title and rights. McMurry alleged damages in this
matter of approximately $30 million. In February 2000, the parties reached a
confidential settlement on all issues for substantially less than the amount
claimed. The amount of the settlement is reflected in the Company's 1999
results of operations. Mountain Gas has not admitted any liability or fault in
the settlement.
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.
50
Berco Resources, Inc. is a producer in the Temple/Tioga Area in North Dakota.
Berco alleged that Amerada Hess engaged in unlawful monopolization under Section
2 of the Sherman Act and Section 7 of the Clayton Act by acquiring natural gas
gathering and producing facilities owned by us. Berco also alleged that the
Company, along with Amerada Hess, had conspired, through the purchase and sale
of its facilities in the Temple/Tioga Area, to create a monopoly affecting an
appreciable amount of interstate commerce in violation of Sections 1 and 2 of
the Sherman Act. Berco sought an award against Amerada Hess and the Company of
threefold the amount of damages actually sustained by it, in an amount to be
determined at trial, and/or divestiture of the assets which Amerada Hess
acquired, or an order restraining and enjoining the Company and Amerada Hess
from violating the antitrust laws, and for costs, attorney fees and interest. In
February 2000 a confidential settlement was reached between the Company and
Berco for an amount which will not have a material impact on the Company's
results of operations or financial position.
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, Producing Properties, Marketing and Transmission, 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 its
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 Black Lake facility and related
reserves are included in this segment. The residue gas and NGLs extracted at the
processing facilities are sold by the Marketing segment.
The activities of the Producing Properties segment includes the exploration and
development of certain oil and gas producing properties in basins where the
Company's facilities are located. The majority of the gas and oil produced from
these properties is sold by the Marketing segment.
The Marketing segment buys and sells gas and NGLs nationwide and in Canada to or
from a variety of customers. In addition, this segment also markets gas and NGLs
produced by the Company's facilities. The operations associated with the
Company's Katy Facility are included in the Marketing segment as are the
Company's Canadian marketing operations (which are immaterial for separate
presentation). Also included in the Marketing segment are gains and losses
associated with the Company's equity hedging program of $(10.9) million, $7.5
million and $(527,000) for the years ended December 31, 1999, 1998 and 1997,
respectively.
The Transmission 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, 1999, 1998 and 1997 (in 000s). Due to the
Company's integrated operations, the use of allocations in the determination of
business segment information is necessary. Intersegment revenues are valued at
prices comparable to those of unaffiliated customers.
51
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)
Intersegment 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
Intersegment 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
(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
======== ======== ========== ======= ======= ========= ==========
52
Gas
Gathering Elim-
and Producing Trans- inating
Processing Properties Marketing mission Corporate Entries Total
---------- ---------- ---------- ------- --------- --------- ----------
Year ended December 31, 1997
Revenues from unaffiliated
customers............................ $ 33,279 $ 1,271 $2,354,276 $ 5,455 $ 4,718 $ - $2,398,999
Interest income...................... 18 - 1 - 27,414 (26,204) 1,229
Other, net........................... (7,835) 2,038 (13,617) 14 (283) - (19,683)
Intersegment sales................... 539,173 17,328 51,410 7,419 46 (615,376) -
-------- -------- ---------- ------- ------- --------- ----------
Total revenues....................... 564,635 20,637 2,392,070 12,888 31,895 (641,580) 2,380,545
-------- -------- ---------- ------- ------- --------- ----------
Product purchases.................... 385,323 1,228 2,363,914 90 - (604,125) 2,146,430
Plant operating expense.............. 72,456 192 7,514 8,209 (2,613) (7,645) 78,113
Oil and gas exploration
and production expense............... 906 6,734 106 - 3 (35) 7,714
-------- -------- ---------- ------- ------- --------- ----------
Operating margin..................... $105,950 $ 12,483 $ 20,536 $ 4,589 $34,505 $ (29,775) $ 148,288
======== ======== ========== ======= ======= ========= ==========
Depreciation, depletion and
amortization......................... 43,311 5,913 4,040 1,054 4,930 - 59,248
Interest expense..................... 27,474
Impairment of property & equip....... 34,615
(Gain) on sale of assets............. (4,715)
Selling and administrative expense... 29,446
----------
Income before income taxes........... $ 2,220
==========
Identifiable assets.................. $698,899 $104,744 $121,305 $48,541 $13,723 $ - $ 987,212
======== ======== ========== ======= ======= ========= ==========
NOTE 10 - EMPLOYEE BENEFIT PLANS
- --------------------------------
Profit Sharing Plan
A discretionary profit sharing plan (a defined contribution plan) exists for all
Company employees meeting certain service requirements. The Company may make
annual discretionary contributions to the plan as determined by the Board of
Directors and provides for a match of 50% of employee contributions on the first
4% of employee compensation contributed. Contributions are made to
common/collective trusts for which Fidelity Management Trust Company acts as
trustee. The discretionary contributions made by the Company were $1.7 million,
$1.9 million and $1.9 million, for the years ended December 31, 1999, 1998 and
1997, respectively. The matching contributions were $541,000, $668,000 and
$310,000 for the years ended December 31, 1999, 1998 and 1997, respectively. Key
Employees' Incentive Stock Option Plan and Non-Employee Director Stock Option
Plan Effective April 1987, the Board of Directors of the Company adopted a Key
Employees' Incentive Stock Option Plan ("Key Employee Plan") and a Non-Employee
Director Stock Option Plan ("Directors' Plan") that authorize the granting of
options to purchase 250,000 and 20,000 shares of the Company's Common Stock,
respectively. Under the plans, each of these options became exercisable as to
25% of the shares covered by it on the later of January 1, 1992 or one year from
the date of grant, subject to the continuation of the optionee's relationship
with the Company, and became exercisable as to an additional 25% of the covered
shares on the later of each subsequent January 1 through 1995 or on each
subsequent date of grant anniversary, subject to the same condition. Each of
these plans terminated on the earlier of February 6, 2000 or the date on which
all options granted under each of the plans have been exercised in full. The
Company has entered into agreements committing the Company to loan certain
employees an amount sufficient to exercise their options as each portion of
their options vests. The Company will forgive such loans and associated accrued
interest if the employee has been continuously employed by the Company for four
years after the date of each loan increment. In January 1999, the Board of
Directors
53
voted to extend the maturity for all such loans for officers still employed in
January 1999, until January 2001. During 1996, under the terms of a severance
agreement, the Company extended the maturity date of one former officer's loans
to December 31, 2000. In addition, under the terms of a severance agreement, the
loans of a former officer are being forgiven over the life of the original loan
forgiveness schedule. As of December 31, 1999 and 1998, loans related to 75,000
and 81,250 shares of Common Stock, respectively, totaling $803,000 and $870,000,
respectively, 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 authorize
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 each of 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 May 24,
1993, May 21, 1997 and on 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 21, 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 price, 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 commencing
with the first anniversary. Under the 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 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.
$5.40 Stock Option Plan
In April 1987 and amended in February 1994, Western Gas Processes, Ltd. adopted
an employee option plan ("$5.40 Plan") that authorized granting options to
employees to purchase 483,000 common units in the Partnership. Pursuant to the
Restructuring, the Company assumed the Partnership's obligation under the
employee option plan. The plan was amended upon the Restructuring to allow each
holder of existing options to exercise such options and acquire one share of
Common Stock for each common unit they were originally entitled to purchase. The
exercise price and all other terms and conditions for the exercise of such
options issued under the amended plan were the same as under the plan, except
that the Restructuring accelerated the time upon which certain options may be
exercised. All options under the plan were either exercised or forfeited on or
before May 31, 1997. The Company has entered into agreements committing the
Company to loan to certain employees an amount sufficient to exercise their
options, provided that the Company will not loan in excess of 25% of the total
amount available to the employee in any one year. In accordance with the
agreements, the Company forgave the majority of such loans and associated
accrued interest on July 2, 1997. Under the terms of a severance agreement, the
Company extended the maturity date of one former officer's loans to December 31,
2000. As of December 31, 1999 and 1998, loans related to 15,000 shares of Common
Stock in each year, respectively, totaling $81,000, were outstanding under these
terms.
The following table summarizes the number of stock options exercisable and
available for grant under the Company's benefit plans:
54
Key 1999
$5.40 Employee Directors' Directors'
Plan Plan Plan Plan 1993 Plan 1997 Plan 1999 Plan
---------- ---------- ---------- ---------- --------- --------- ---------
Exercisable:
December 31, - - - - 407,787 47,240 -
1999............
December 31, - 75,000 13,500 - 562,138 26,250 -
1998............
December 31, - 75,000 12,250 - 448,171 - -
1997............
Available for Grant:
December 31, - - - - - 350,000 714,734
1999............
December 31, - 31,250 1,250 - 96,609 763,400 -
1998............
December 31, - 31,250 1,250 - 9,382 828,900 -
1997............
55
The following table summarizes the stock option activity under the Company's
benefit plans:
Number of Shares
----------------------------------------------------------------------------------------
1999
Per Share $ 5.40 Key Employee Directors' Directors'
Price Range Plan Plan Plan Plan 1993 Plan 1997 Plan 1999 Plan
------------ -------- ------------ ---------- ------------ ---------- --------- ---------
Balance 12/31/96 33,148 75,000 13,500 - 993,203 - -
Granted $17.75-24.00 - - - - 64,654 171,100 -
Excercised $ 5.40-23.50 (32,077) - - - (5,225) - -
Forfeited or $ 5.40-34.13 (1,071) - - - (69,302) - -
canceled
----------------------------------------------------------------------------------------
Balance 12/31/97 - 75,000 13,500 - 983,330 171,100 -
Granted $ 19.28 - - - - 40,511 106,500 -
Excercised $ 15.83 - - - - (1,556) - -
Forfeited or $19.19-21.78 - - - - (129,809) (41,000) -
canceled
----------------------------------------------------------------------------------------
Balance 12/31/98 - 75,000 13,500 - 892,476 236,600 -
Granted $ 4.59-17.11 - - - 15,000 - 505,500 35,266
Excercised $10.71-16.50 - - (8,500) - (1,938) (3,300) -
Forfeited or $ 4.59-35.50 - (75,000) (5,000) - (324,664) (92,100) -
canceled
----------------------------------------------------------------------------------------
Balance 12/31/99 - - - 15,000 565,874 646,700 35,266
========================================================================================
The following table summarizes the weighted average option exercise price
information under the Company's benefit plans:
1999
Key Employee Directors' Directors'
$5.40 Plan Plan Plan Plan 1993 Plan 1997 Plan 1999 Plan
---------- ------------ ----------- ---------- --------- ---------- ---------
Balance 12/31/96 $ 5.40 $ 30.23 $ 14.13 $ - $ 21.31 $ - $ -
Granted - - - - 19.71 19.63 -
Excercised 5.40 - - - 16.91 - -
Forfeited or canceled 5.40 - - - 25.54 - -
---------- ------------ ----------- ---------- --------- ---------- ---------
Balance 12/31/97 - 30.23 14.13 - 20.93 19.63 -
Granted - - - - 19.28 11.69 -
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
========== ============ =========== ========== ========= ========== =========
SFAS No. 123 encourages companies to record compensation expense for stock-based
compensation plans at fair value. As permitted under SFAS No. 123, the Company
has elected to continue to measure compensation costs for such plans as
prescribed by APB No. 25. SFAS No. 123 requires pro forma disclosures for each
year a statement of operations is
56
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 $9.25, $1.00 and $12.66 for the years
ended December 31, 1999, 1998 and 1997, respectively. The weighted average fair
value of options granted under the 1999 Plan was $6.82 for the year ended
December 31, 1999. 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
1999 Plan 1997 Plan Directors' Plan
--------------- -------------------------- ---------------
1999 1999 1998 1997 1999
--------------- ------ ---------- ------ ---------------
Risk-free interest rate......... 6.96% 6.96% 5.3% 6.1% 6.96%
Expected life (in years)........ 5 5 6 10 5
Expected volatility............. 51% 51% 45% 42% 51%
Expected dividends (quarterly).. $ .05 $ .05 $ .05 $ .05 $ .05
Had compensation expense for the Company's 1999, 1998 and 1997 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):
1999 1998 1997
------------------------ ------------------------ ------------------------
As Reported Pro forma As Reported Pro forma As Reported Pro forma
------------ ---------- ------------ ---------- ------------ ----------
Net income (loss).................... $(17,124) $(18,589) $(67,205) $(67,997) $ 1,487 $ 941
Net income (loss) attributable to
common stock........................ (27,563) (29,028) (77,644) (78,436) (8,952) (9,498)
Earnings (loss) per share of common
stock............................... (.86) (.90) (2.42) (2.44) (.28) (.30)
Earnings (loss) per share of common
stock - assuming dilution.......... $ (.86) $ (.90) $ (2.42) $ (2.44) $ (.28) $ (.30)
The 1993 Plan dictates that the options granted vest 20% each year on the
anniversary of the date of grant commencing with the first anniversary. The
Board of Directors has the authority to set the vesting schedule from 20% per
year to 33 1/3% per year for the 1997 and 1999 Plans. As a result, no
compensation expense, as defined under SFAS No. 123, is recognized in the year
options are granted. In addition, the fair market value of the options at grant
date is amortized over 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, 1999, 1998 and
1997 and costs incurred for oil and gas producing activities for the years ended
December 31, 1999, 1998 and 1997 (000s):
57
1999 1998 1997
--------- --------- ---------
Capitalized costs:
Proved properties............................................... $ 74,594 $110,090 $134,102
Unproved properties............................................. 42,928 33,255 18,464
-------- -------- --------
Total............................................................ 117,522 143,345 152,566
Less accumulated depletion...................................... (23,003) (58,994) (61,766)
-------- -------- --------
Net capitalized costs............................................ $ 94,519 $ 84,351 $ 90,800
======== ======== ========
The Company's share of Redman Smackover's net capitalized costs.. $ - $ - $ 3,845
======== ======== ========
Costs incurred:
Acquisition of properties
Proved.......................................................... $ - $ 2,174 $ 7,499
Unproved........................................................ 11,675 22,633 10,457
Development costs................................................ 20,973 23,208 13,134
Exploration costs................................................ 5,148 4,177 1,322
-------- -------- --------
Total costs incurred............................................. $ 37,796 $ 52,192 $ 32,412
======== ======== ========
The Company's share of Redman Smackover's costs incurred......... $ - $ 72 $ 236
======== ======== ========
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, 1999,
1998 and 1997 are as follows (000s):
1999 1998 1997
--------- --------- ---------
Revenues from sale of oil and gas:
Sales................................................ $ 2,081 $ 2,592 $ 5,970
Transfers............................................ 30,537 23,188 25,571
-------- -------- --------
Total.............................................. 32,618 25,780 31,541
Production costs...................................... (8,002) (6,611) (6,384)
Exploration costs (1,492) (1,599) (1,439)
Depreciation, depletion and amortization.............. (11,536) (11,749) (11,549)
Impairment of oil and gas properties.................. - (16,528) (19,615)
Income tax benefit (expense).......................... (3,921) (3,690) 2,792
-------- -------- --------
Results of operations................................. $ 7,667 $ (7,017) $ (4,654)
======== ======== ========
The Company's share of Redman Smackover's operations.. $ - $ 421 $ 1,265
======== ======== ========
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
58
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,
1999, 1998 and 1997 with respect to changes in the Company's proved reserves,
all of which are in the United States. The Company has no significant
undeveloped reserves.
Natural Crude
Gas Oil
(MMcf) (MBbls)
-------- -------
Proved reserves:
December 31, 1996.......................................... 96,031 843
Revisions of previous estimates............................ (18,132) (74)
Extensions and discoveries................................. 113,251 191
Purchases of reserves in place............................. 34,588 -
Production................................................. (13,142) (154)
------- ----
December 31, 1997.......................................... 212,596 806
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
======= ====
The Company's share of Redman Smackover's proved reserves:
December 31, 1997.......................................... 10,218 -
======= ====
December 31, 1998.......................................... - -
======= ====
December 31, 1999.......................................... - -
======= ====
Standardized Measures of Discounted Future Net Cash Flows
Estimated discounted future net cash flows and changes therein were determined
in accordance with SFAS No. 69, "Disclosures about Oil and Gas Producing
Activities." Certain information concerning the assumptions used in computing
the valuation of proved reserves and their inherent limitations are discussed
below. The Company believes such information is essential for a proper
understanding and assessment of the data presented.
Future cash inflows are computed by applying year end prices of oil and gas
relating to the Company's proved reserves to the year end quantities of those
reserves.
59
The assumptions used to compute estimated future net revenues do not necessarily
reflect the Company's expectations of actual revenues or costs, nor their
present worth. In addition, variations from the expected production rate also
could result directly or indirectly from factors outside of the Company's
control, such as unintentional delays in development, changes in prices or
regulatory controls. The reserve valuation further assumes that all reserves
will be disposed of by production. However, if reserves are sold in place,
additional economic considerations could also affect the amount of cash
eventually realized.
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, 1999, 1998 and
1997 is as follows (000s):
1999 1998 1997
---------- ---------- ----------
Future cash inflows......................................................... $ 419,104 $ 345,217 $ 352,491
Future production costs..................................................... (121,129) (108,457) (118,056)
Future development costs.................................................... (57,999) (46,066) (28,803)
Future income tax expense................................................... (44,130) (33,749) (32,614)
--------- --------- ---------
Future net cash flows....................................................... 195,846 156,945 173,018
10% annual discount for estimated timing of cash flows...................... (82,919) (59,068) (73,445)
--------- --------- ---------
Standardized measure of discounted future net cash flows relating to
proved oil and gas reserves............................................... $ 112,927 $ 97,877 $ 99,573
========= ========= =========
The Company's share of Redman Smackover's standardized measure of
discounted future net cash flows relating to proved oil and gas reserves.. $ - $ - $ 6,326
========= ========= =========
60
Principal changes in the Company's estimated discounted future net cash flows
for the years ended December 31, 1999, 1998 and 1997 are as follows (000s):
1999 1998 1997
-------- -------- ---------
January 1............................................. $ 97,877 $ 99,573 $ 110,717
Sales and transfers of oil and gas produced, net of
production costs.................................... (24,616) (19,170) (25,157)
Net changes in prices and production costs related
to future production................................ 19,569 367 (146,968)
Development costs incurred during the period......... 20,973 23,208 13,134
Changes in estimated future development costs........ (29,725) (33,723) (26,875)
Changes in extensions and discoveries................ 26,597 23,336 158,314
Revisions of previous quantity estimates............. 9,028 35,438 (47,859)
Purchases (sales) of reserves in place............... (5,842) (38,251) 47,867
Accretion of discount................................ 9,788 9,957 11,072
Net change in income taxes........................... (10,381) (1,134) 5,256
Other, net........................................... - (1,724) 72
-------- -------- ---------
December 31........................................... $113,268 $ 97,877 $ 99,573
======== ======== =========
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
--------- --------- --------- -------------- ---------------
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)
========== ======== ========= ============== ==============
1998 quarter ended:
March 31............................................. $565,504 $ 36,394 $ 13,185 $ .33 $ .33
June 30.............................................. 500,945 10,876 (2,609) (.16) (.16)
September 30......................................... 516,253 8,301 (4,653) (.23) (.23)
December 31.......................................... 534,386 10,457 (73,128) (c) (2.36) (2.36)
--------- -------- --------- -------------- --------------
$2,117,088 $ 66,028 $ (67,205) $(2.42) $(2.42)
========== ========= ========= ============== ==============
(a) Excludes selling and administrative, interest and income tax expenses and
loss on the impairment of property and equipment.
(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.
(c) Includes a pre-tax, non-cash expense resulting from the evaluation of
property and equipment in accordance with SFAS No. 121 of $108.5 million.
61
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Pursuant to instruction G(3) to Form 10-K, Items 10, 11, 12 and 13 are omitted
because the Company will file a definitive proxy statement (the "Proxy
Statement") pursuant to Regulation 14A under the Securities Exchange Act of 1934
not later than 120 days after the close of the fiscal year. The information
required by such Items will be included in the definitive proxy statement to be
so filed for the Company's annual meeting of stockholders scheduled for May 19,
2000 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 30 for a list of all financial statements
filed as a part of this report.
(2) Financial Statement Schedules:
None required.
(3) Exhibits:
3.1 Certificate of Incorporation of Western Gas Resources, Inc. (Filed as
exhibit 3.1 to Western Gas Resources, Inc.'s Registration Statement on Form S-1,
Registration No. 33-31604 and incorporated herein by reference).
3.2 Certificate of Amendment to the Certificate of Incorporation of
Western Gas Resources, Inc. (Filed as exhibit 3.2 to Western Gas Resources,
Inc.'s Registration Statement on Form S-1, Registration No. 33-31604 and
incorporated herein by reference).
3.3 Certificate of Designation of 7.25% Cumulative Senior Perpetual
Convertible Preferred Stock of the Company (Filed as exhibit 3.5 to Western Gas
Resources, Inc.'s Registration Statement on Form S-1, Registration No. 33-43077
dated November 14, 1991 and incorporated herein by reference).
3.4 Certificate of Designation of $2.28 Cumulative Preferred Stock of the
Company (Filed as exhibit 3.6 to Western Gas Resources, Inc.'s Registration
Statement of Form S-1, Registration No. 33-53786 dated November 12, 1992 and
incorporated herein by reference).
3.5 Certificate of Designation of the $2.625 Cumulative Convertible
Preferred Stock of the Company (Filed under cover of Form 8-K dated February 24,
1994 and incorporated herein by reference).
4.1 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.
4.2 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.
4.3 Western Gas Resources, Inc., 10% Senior Subordinated Notes due 2009
(filed as an exhibit to Western Gas Resources Inc.'s Registration Statement on
Form S-4, Registration No. 33-333-86881 dated September 10, 1999) and
incorporated herein by reference.
4.4 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.
62
10.1 Restated Profit-Sharing Plan and Trust Agreement of Western Gas
Resources, Inc. (Filed as exhibit 10.8 to Western Gas Resources, Inc.'s
Registration Statement on Form S-4, Registration No. 33-39588 dated March 27,
1991 and incorporated herein by reference).
10.2 Western Gas Resources, Inc. Key Employees' Incentive Stock Option Plan
(Filed as exhibit 10.13 to Western Gas Resources, Inc.'s Registration Statement
on Form S-4, Registration No. 33-39588 dated March 27, 1991 and incorporated
herein by reference).
10.3 Registration Rights Agreement among Western Gas Resources, Inc., WGP,
Inc., Heetco, Inc., NV, Dean Phillips, Inc., Sauvage Gas Company and Sauvage Gas
Service, Inc. (Filed as exhibit 10.14 to Western Gas Resources, Inc.'s
Registration Statement on Form S-4, Registration No. 33-39588 dated March 27,
1991 and incorporated herein by reference).
10.4 Amendment No. 1 to Registration Rights Agreement as of May 1, 1991
between Western Gas Resources, Inc., Bill Sanderson, WGP, Inc., Dean Phillips,
Inc., Heetco, Inc., NV, Sauvage Gas Company and Sauvage Gas Service, Inc. (Filed
as exhibit 4.2 to Western Gas Resources, Inc.'s Form 10-Q for the quarter ended
June 30, 1991 and incorporated herein by reference).
10.5 Second Amendment and First Restatement of Western Gas Processors, Ltd.
Employees' Common Units Option Plan (Filed as exhibit 10.6 to Western Gas
Resources, Inc.'s Registration Statement on Form S-1, Registration No. 33-43077
dated November 14, 1991 and incorporated herein by reference).
10.6 Agreement to provide loans to exercise key employees' common stock
options (Filed as exhibit 10.26 to Western Gas Resources, Inc.'s Annual Report
on Form 10-K for the fiscal year ended December 31, 1991 and incorporated herein
by reference).
10.7 Agreement to provide loans to exercise employees' common stock options
(Filed as exhibit 10.27 to Western Gas Resources, Inc.'s Annual Report on Form
10-K for the fiscal year ended December 31, 1991 and incorporated herein by
reference).
10.8 Note Purchase Agreement (without exhibits) dated as of April 1, 1993 by
and between the Company and the Purchasers for $50,000,000, 7.65% Senior Notes
Due April 30, 2003 (Filed as exhibit 10.48 to Western Gas Resources, Inc.'s Form
10-Q for the six months ended June 30, 1993 and incorporated herein by
reference).
10.9 General Partnership Agreement (without exhibits), dated August 10, 1993
for Westana Gathering Company by and between Western Gas Resources-Oklahoma,
Inc. (a subsidiary of the Company) and Panhandle Gathering Company (Filed as
exhibit 10.50 to Western Gas Resources, Inc.'s Form 10-Q for the six months
ended June 30, 1993 and incorporated herein by reference).
10.10 Amendment to General Partnership Agreement dated August 10, 1993 by and
between Western Gas Resources-Oklahoma, Inc. (a subsidiary of the Company) and
Panhandle Gathering Company (Filed as exhibit 10.51 to Western Gas Resources,
Inc.'s Form 10-Q for the six months ended June 30, 1993 and incorporated herein
by reference).
10.11 Amendment No. 1 to Note Purchase Agreement dated as of August 31, 1993
by and among the Company and the Purchasers (Filed as exhibit 10.61 to Western
Gas Resources, Inc.'s Form 10-Q for the nine months ended September 30, 1993 and
incorporated herein by reference).
10.12 Amendment No. 2 to Note Purchase Agreement dated as of August 31, 1994
by and among Western Gas Resources, Inc. and the Purchasers (Filed as exhibit
10.68 to Western Gas Resources, Inc.'s Form 10-Q for the nine months ended
September 30, 1994 and incorporated herein by reference).
10.13 Amendment No. 3 to Note Purchase Agreement as of March 22, 1995 by and
among Western Gas Resources, Inc. and the Purchasers (Filed as exhibit 10.38 to
Western Gas Resources, Inc.'s Form 10-Q for the three months ended March 31,
1995 and incorporated herein by reference).
10.14 Form of Employment Agreement by and between Western Gas Resources, Inc.
and certain Executive Officers (Filed as exhibit 10.40 to Western Gas Resources,
Inc.'s Form 10-Q for the three months ended March 31, 1995 and incorporated
herein by reference).
63
10.15 Amendment No. 4 to Note Purchase Agreements as of July 14, 1995 by and
among Western Gas Resources, Inc. and the Purchasers (Filed as exhibit 10.43 to
Western Gas Resources, Inc.'s Form 10-Q for the six months ended June 30, 1995
and incorporated herein by reference).
10.16 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).
10.17 Fourth Amendment to First Restated Loan Agreement (Revolver) dated
November 29, 1995 by and among Western Gas Resources, Inc. and NationsBank, as
agent, and the Lenders (Filed as exhibit 10.51 to Western Gas Resources, Inc.'s
Form 10-K for the year ended December 31, 1995 and incorporated herein by
reference).
10.18 Senior Note Purchase Agreement dated November 29, 1995 by and among
Western Gas Resources, Inc. and the Purchasers identified therein (Filed as
exhibit 10.52 to Western Gas Resources, Inc.'s Form 10-K for the year ended
December 31, 1995 and incorporated herein by reference).
10.19 Loan Agreement dated May 30, 1997 among Western Gas Resources, Inc. and
NationsBank of Texas, N.A. as agent, Bank of America National Trust and Savings
Association as Co-agent and Certain Banks as Lenders (Revolver) (Filed as
exhibit 10.40 to Western Gas Resources, Inc.'s Form 10-Q for the six months
ended June 30, 1996 and incorporated herein by reference).
11.1 Statement regarding computation of per share earnings.
12.1 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. Form 10-K for the year ended December 31, 1998 and incorporated
herein by reference).
12.2 Second Amendment dated February 17, 1999 to Credit Agreement by and among
Western Gas Resources, Inc. and NationsBank N.A., successor to NationsBank of
Texas, N.A., by merger, and the Lenders identified in the Original Agreement
dated May 30, 1997. (Filed as exhibit 12.2 to Western Gas Resources, Inc. Form
10-K for the year ended December 31, 1998 and incorporated herein by reference).
12.3 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 to Western Gas Resources, Inc.
Form 10-K for the year ended December 31, 1998 and incorporated herein by
reference).
12.4 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 to Western Gas Resources, Inc. Form 10-K for the year
ended December 31, 1998 and incorporated herein by reference).
12.5 Loan Agreement dated February 17, 1999 by and among Western Gas
Resources, Inc. and NationsBank, N.A., for $37,000,000 Bridge Loan. (Filed as
exhibit 12.5 to Western Gas Resources, Inc. Form 10-K for the year ended
December 31, 1998 and incorporated herein by reference).
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 8-K on May 10, 1999 announcing
the sale of the Katy Storage Facility in Texas and financial information
related thereto, which is incorporated herein by reference.
Western Gas Resources, Inc., filed a report on 8-K on May 25, 1999 announcing
an agreement for the sale of its assets in the MiVida facility in Texas, which
is incorporated herein by reference.
Western Gas Resources, Inc., filed a report on 8-K on May 27, 1999 announcing
the offering of $150,000,000 in Senior Subordinated Notes due in 2009, which
is incorporated herein by reference.
Western Gas Resources, Inc., filed a report on 8-KA on July 7, 1999 amending
certain previously filed financial information, which is incorporated herein
by reference.
Western Gas Resources, Inc., filed a report on 8-K on September 22, 1999
announcing the appointment of Lanny F. Outlaw as Chief Executive Officer and
President, and Brion G. Wise as Chairman of the Board, which is incorporated
herein by reference.
Western Gas Resources, Inc., filed a report on 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.
Western Gas Resources, Inc., filed a report on 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.
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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 13, 2000.
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 13, 2000
- -----------------------
Brion G. Wise
Vice Chairman of the Board March 13, 2000
/S/ W. L. Stonehocker and Director
- -----------------------
Walter L. Stonehocker
/S/ B. M. Sanderson Director March 13, 2000
- -----------------------
Bill M. Sanderson
/S/ Richard B. Robinson Director March 13, 2000
- -----------------------
Richard B. Robinson
/S/ Dean Phillips Director March 13, 2000
- -----------------------
Dean Phillips
S/ Ward Sauvage Director March 13, 2000
- -----------------------
Ward Sauvage
/S/ James A. Senty Director March 13, 2000
- -----------------------
James A. Senty
/S/ Joseph E. Reid Director March 13, 2000
- -----------------------
Joseph E. Reid
Vice President - Finance
(Principal Financial and
/S/ William J. Krysiak Accounting Officer) March 13, 2000
- -----------------------
William J. Krysiak
65