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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 [Fee Required] for the fiscal year ended December 31, 1995 or
[ ] Transition report pursuant to section 13 or 15(d) of the Securities
Exchange Act of 1934 [No Fee Required] for the transition period from
_________________ to _________________
Commission file number 1-10389
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WESTERN GAS RESOURCES, INC.
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(Exact name of registrant as specified in its charter)
Delaware 84-1127613
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
12200 N. Pecos Street, Denver, Colorado 80234-3439
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(Address of principal executive offices) (Zip Code)
(303) 452-5603
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Registrant's telephone number, including area code
No Changes
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(Former name, former address and former fiscal year, if changed since last
report).
Title of each class Name of exchange on which registered
- ----------------------------- ------------------------------------
Common Stock, $0.10 par value New York Stock Exchange
$2.28 Cumulative Preferred Stock, $0.10 par value New York Stock Exchange
$2.625 Cumulative Convertible Preferred Stock, New York Stock Exchange
$0.10 par value
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, 1996 was $183,434,693.
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this Report (Items 10, 11, 12 and 13) is
incorporated by reference from the registrant's proxy statement to be filed
pursuant to Regulation 14A with respect to the annual meeting of stockholders
scheduled to be held on May 22, 1996.
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. [ ]
Reference is made to listing beginning on page 52 of all exhibits filed as a
part of this report.
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Western Gas Resources, Inc.
Form 10-K
Table of Contents
Part Item(s) Page
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I. 1 and 2. Business and Properties........................................... 3
General......................................................... 3
Principal Facilities............................................ 4
Gas Gathering and Processing.................................... 5
Significant Acquisitions and Projects........................... 6
Marketing....................................................... 8
Producing Properties............................................ 9
Competition..................................................... 9
Regulation...................................................... 10
Insurance and Operational Risks................................. 10
Employees....................................................... 11
3. Legal Proceedings................................................. 11
4. Submission of Matters to a Vote of Security Holders............... 11
II. 5. Market for Registrant's Common Equity and Related
Stockholder Matters............................................... 12
6. Selected Financial Data........................................... 13
7. Management's Discussion and Analysis of Financial
Condition and Results of Operations............................. 14
8. Financial Statements and Supplementary Data....................... 25
9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure............................... 51
III. 10. Directors and Executive Officers of the Registrant................ 51
11. Executive Compensation............................................ 51
12. Security Ownership of Certain Beneficial Owners and
Management...................................................... 51
13. Certain Relationships and Related Transactions.................... 51
IV. 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K........................................................ 52
2
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
GENERAL
Western Gas Resources, Inc. (the "Company") is an independent gas gatherer,
processor and marketer with operations located in major oil- and gas-producing
basins in the Rocky Mountain, Gulf Coast and Southwestern regions of the United
States. The Company owns and operates natural gas gathering, processing and
storage facilities and markets and transports natural gas and natural gas
liquids ("NGLs"). The Company provides necessary services to the producers of
natural gas and NGLs by connecting producers' wells to the Company's gathering
system for delivery to its processing plants, processing the gas to remove NGLs
and by-products and marketing the gas and NGLs throughout the United States.
Most of the natural gas processed by the Company is associated gas from oil
wells. The Company also owns certain producing properties, primarily in
Louisiana and Texas.
Historically, the Company has derived over 95% of its revenues from the sale of
natural gas and NGLs. Set forth below are the Company's revenues by type of
operation (000s):
Year Ended December 31,
----------------------------------------------------------------------
1995 % 1994 % 1993 %
---------- --------- ---------- -------- --------- ------
Sale of residue gas............... $ 876,399 69.7 $ 707,869 66.6 $ 563,068 60.4
Sale of NGLs...................... 331,760 26.4 309,358 29.1 333,880 35.8
Processing, transportation and
storage revenues................ 41,358 3.3 35,057 3.3 25,622 2.7
Other, net........................ 7,467 .6 11,205 1.0 9,768 1.1
---------- --------- ---------- --------- --------- ------
$1,256,984 100.0 $1,063,489 100.0 $ 932,338 100.0
========== ========= =========== ========= ========= ======
The Company expanded through acquisitions, internal project development and
increased marketing activity. These activities have strengthened the Company's
position in major producing basins and expanded its access to multiple natural
gas markets. The table below illustrates the Company's growth from December 31,
1990 to December 31, 1995:
Average Average Average for the Year Ended
--------------------------------------
Residue NGL Gas Gas NGL
Gas Sales Sales Throughput Production Production
(MMcf/D) (MGal/D) (MMcf/D) (MMcf/D) (MGal/D)
--------- -------- ---------- ---------- ----------
December 31, 1990............ 220 630 217 164 680
December 31, 1995............ 1,572 2,890 1,020 779 2,181
% increase................... 615 359 370 375 221
The Company has developed a three-part business plan to increase profitability
through expanding its gas marketing activities, acquiring or developing gas
gathering and processing assets that meet the Company's target rates of return
and increasing the efficiency of its existing facilities. As a part of its
initial implementation of the business plan, the Company has (i) restructured
its marketing department along more specialized lines designating separate
managers for national accounts, end-use sales and electric power marketing, (ii)
added business development personnel dedicated to acquiring gas supplies for its
existing facilities, and (iii) reduced its operating expenses. See further
discussion at "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Forward Looking Information."
The Company's principal offices are located at 12200 North Pecos Street, Denver,
Colorado 80234-3439, and its telephone number is (303) 452-5603. The Company was
incorporated in Delaware in 1989.
3
PRINCIPAL FACILITIES
The following table provides information concerning the Company's principal
facilities. The Company also owns and operates several smaller treating and
processing facilities located in the same areas as its other facilities.
Average for the year ended
Gas Gas December 31, 1995
------------------------------------------
Gathering Throughput Gas Gas NGL
Year Placed Systems Capacity Throughput Production Production
Facility (1) In Service Miles(2) (MMcf/D)(2) (MMcf/D)(3) (MMcf/D)(4) (MGal/D)(4)
- --------------------------------- ---------- -------- ----------- ----------- ----------- -----------
SOUTHERN REGION:
Texas
Midkiff /Benedum............... 1955 2,042 135 135 87 835
Giddings Gathering System...... 1979 651 80 71 62 99
Edgewood(5)(8)................. 1964 85 65 28 11 74
Perkins........................ 1975 2,564 40 21 12 146
MiVida (5)..................... 1972 286 150 44 41 -
Gomez(13)...................... 1971 302 280 72 69 -
Mitchell Puckett(13)........... 1972 86 140 - - -
Crockett Gathering System...... 1973 136 - 27 27 1
Rosita Treating System......... - 60 56 56 -
Katy(6)........................ 1994 17 - - - -
Louisiana
Black Lake..................... 1966 55 75 53 36 120
Toca(7)(8)..................... 1958 - 160 74 - 49
NORTHERN REGION:
Oklahoma
Chaney Dell/Lamont............. 1966 2,003 180 83 63 259
Arkoma......................... 1985 38 8 2 2 -
Westana System(9).............. 1986 246 45 55 48 49
Wyoming
Granger(8)..................... 1987 236 210 130 119 189
Red Desert(8).................. 1979 110 42 30 27 45
Lincoln Road(10)............... 1988 146 50 38 35 41
Hilight Complex(5)(8).......... 1969 619 80 34 29 86
Kitty and Amos Draw(8)......... 1969 304 17 11 8 47
Newcastle(8)................... 1981 144 5 3 2 19
Reno Junction(11).............. 1991 - - - - 49
New Mexico
San Juan River(5).............. 1955 126 60 33 30 1
North Dakota
Williston(12).................. 1981 381 - 8 6 28
Temple(5)...................... 1984 65 7 3 2 8
Teddy Roosevelt(12)............ 1979 332 - 3 2 14
Utah
Four Corners................... 1988 97 15 4 4 10
Montana
Baker(5)(8).................... 1981 8 3 2 1 12
------ ----- ----- --- -----
Total......................... 11,079 1,907 1,020 779 2,181
====== ===== ===== === =====
_____________________________
Footnotes on following page
4
(1) The Company's interest in all facilities is 100% except for Midkiff/Benedum
(74%); Black Lake (69%); Lincoln Road (72%); Williston (50%); Westana (50%)
and Newcastle (50%). All facilities are operated by the Company and all
data include interests of the Company, other joint interest owners and
producers of gas volumes dedicated to the facility.
(2) Gas gathering systems miles and gas throughput capacity are as of December
31, 1995.
(3) Aggregate wellhead natural gas volumes collected by a gathering system.
(4) Volumes of residue gas and NGLs are allocated to a facility when a well is
dedicated to that facility; volumes exclude NGLs fractionated for third
parties.
(5) Sour gas facility (capable of processing gas containing hydrogen sulfide).
(6) Hub and gas storage facility.
(7) Straddle plant (a plant located near a transmission pipeline which
processes gas dedicated to or gathered by the pipeline company or another
third-party).
(8) Fractionation facility (capable of fractionating raw NGLs into end-use
products).
(9) Gas throughput and gas production in excess of gas throughput capacity is
unprocessed gas delivered directly to an unaffiliated pipeline.
(10) Commencing in March 1996, the Company and its joint venture partner at the
Lincoln Road gas plant temporarily suspended processing operations at the
Lincoln Road plant and began processing the related gas at the Company's
Granger facility. If volumes increase substantially beyond Granger's
capacity, the Lincoln Road plant might be re-started. The Company
anticipates that this consolidation will result in lower overall plant
operating expenses for the combined systems.
(11) NGL production represents conversion of third-party feedstock to iso-
butane.
(12) Processing facility has been shut-in since August 1993. The gas dedicated
to these facilities is processed by a third-party under a contractual
arrangement. In January 1996, Koch Hydorcarbon Company ("Koch"), which
operates the Teddy Roosevelt and Williston Gas Company's ("Williston")
assets under a lease agreement, exercised its option to purchase certain
gas gathering assets located in North Dakota from the Company and
Williston. The closing of the sale is expected to occur on August 1, 1996.
See further discussion at "Significant Acquisitions and Projects - Other."
(13) Includes assets purchased in October and December 1995 that were combined
with these existing facilities.
Capital expenditures related to existing operations are expected to be
approximately $76.1 million during 1996 consisting of the following: capital
expenditures related to gathering, processing and pipeline assets are expected
to be $63.2 million, of which $47.6 million will be used for new well connects,
system expansions and asset consolidations and $15.6 million for maintaining
existing facilities. The Company expects capital expenditures on the Katy Gas
Storage Facility ("Katy Facility"), exploration and production activities and
miscellaneous items to be $4.8 million, $3.8 million and $4.3 million,
respectively.
GAS GATHERING AND PROCESSING
The Company contracts with producers to gather raw natural gas from individual
wells located near its plants. Once a contract has been executed, the Company
connects wells to gathering lines through which the natural gas is delivered to
a processing plant. At the plant, the natural gas is compressed, unfractionated
NGLs are extracted, and the remaining dry residue gas is treated to meet
pipeline quality specifications. Eight of the Company's processing plants can
further separate, or fractionate, the mixed NGL stream into ethane, propane,
butane and natural gasoline to obtain higher value for the NGLs, and six of the
Company's plants are able to process and treat natural gas containing hydrogen
sulfide or other impurities which require removal prior to transportation. In
addition, the Company has one facility which converts normal butane into iso-
butane.
The Company continually acquires additional natural gas supplies to maintain or
increase throughput levels to offset natural production declines in dedicated
volumes. Such natural gas supplies are obtained by purchasing existing systems
from third parties or by connecting additional wells. The opportunity to
connect new wells to existing facilities is primarily affected by levels of
drilling activity near the Company's gathering systems. The Company believes it
has expanded into areas which present significant potential for new drilling or
purchases of existing systems. Historically, the Company has connected
additional reserves which more than offset production from reserves dedicated to
existing facilities. However, certain individual plants have experienced
declines in dedicated reserves. In 1995, including the reserves associated with
Westana Gathering Company ("Westana") and 1995 acquisitions, the Company
connected new reserves to its gathering systems to replace approximately 94% of
1995 production. On a Company-wide basis, dedicated reserves, including certain
proved undeveloped properties and revisions to previous estimates, decreased
from 2.3 Tcf as of December 31, 1994 (as revised) to approximately 2.1 Tcf at
December 31, 1995. The decrease is primarily due to decreased drilling in areas
in which the Company operates and declines in reserves at the Company's Black
Lake field.
Substantially all gas flowing through the Company's facilities is supplied under
long-term contracts providing for the purchase or processing of such gas for
periods ranging from five to twenty years, using three basic contract types.
Approximately 57% of the
5
Company's gas throughput (exclusive of the Toca straddle plant) for the year
ended December 31, 1995 was purchased under percentage-of-proceeds agreements in
which the Company is typically responsible for arranging for the transportation
and marketing of the natural gas and NGLs. The price paid to producers is a
specified percentage of the net proceeds received from the sale of the natural
gas and the NGLs. This type of contract permits the Company and the producers to
share proportionally in price changes.
Approximately 24% of the Company's gas throughput for the year ended December
31, 1995 was gathered under contracts which are primarily fee-based whereby the
Company receives a set fee for each Mcf of gas gathered. This type of contract
provides the Company with a steady revenue stream that is not dependent on
commodity prices, except to the extent that low prices may cause a producer to
curtail production.
Approximately 19% of the Company's gas throughput for the year ended December
31, 1995 was processed under contracts which combine gathering and compression
fees with "keep-whole" arrangements or well-head purchases. Typically, producers
are charged a gathering and compression fee based upon volume. In addition, the
Company retains a predetermined percentage of the NGLs recovered by the
processing facility and keeps the producers whole by returning to the producers
at the tailgate of the plant an amount of residue gas equal on a Btu basis to
the raw gas received at the plant inlet. The "keep-whole" component of the
contracts permits the Company to benefit when the value of the NGLs is greater
as a liquid than as a portion of the residue gas stream. However, when the value
of the NGLs is lower as a liquid than as a portion of the residue gas stream,
the Company may be affected unfavorably.
SIGNIFICANT ACQUISITIONS AND PROJECTS
The Company's significant acquisitions and projects since January 1, 1993 are:
Northern Acquisition
In July 1995, the Company entered into an agreement to purchase eight West Texas
gathering systems, consisting of approximately 230 miles of gathering lines in
the Permian Basin, from Transwestern Gathering Company and Enron Permian
Gathering, Inc. In October 1995, the Company acquired and assumed the operations
of the Transwestern Gathering Company assets for an adjusted purchase price of
$4.0 million. Closing on the remaining assets occurred in December 1995 for a
purchase price of $14.7 million. For the month ended January 31, 1996,
throughput on the systems totaled approximately 150 MMcf per day from
approximately 70 wells under fee-based contracts.
Redman Smackover Joint Venture
Effective January 1, 1995, the Company entered into the Redman Smackover Joint
Venture ("Redman Smackover") agreement with DDD Energy, Inc., a wholly owned
exploration and production subsidiary of Seitel, Inc., Redman Energy
Corporation, and DDD 1995 Oil & Gas Partnership. Redman Smackover acquired
working interests in three producing gas fields in East Texas in the Smackover
formation with an estimated 25 Bcf of proved reserves from Union Oil Company of
California for an adjusted purchase price of $11.0 million. The Company's
contribution to Redman Smackover was approximately $5.4 million through December
31, 1995. The Company is the managing venturer with a 50% ownership interest.
Oasis
Effective December 1, 1994, the Company acquired the West Texas gathering and
treating assets of Oasis Pipeline Company ("Oasis") for approximately $26.0
million. The Oasis purchase included 14 gathering systems in the Permian Basin
comprising approximately 600 miles of gathering lines and two treating
facilities. In addition, the Company entered into a long-term agreement with
Oasis for 100 MMcf per day of firm transportation service on its intrastate
pipeline. The Company has installed a 200 MMcf per day pipeline interconnection
between this pipeline and the Katy Facility.
Katy Facility
The Company commenced operations of the Katy Facility in February 1994. The Katy
Facility, which is located approximately 20 miles from Houston, Texas, utilizes
a partially depleted natural gas reservoir with 19 Bcf of working gas capacity
and a pipeline header system, currently connected to eleven pipelines, which has
the capability to deliver up to 400 MMcf per day of natural gas from the
reservoir. Lease acquisition and construction costs incurred through the
commencement of operations, including pad gas, approximated $106.1 million. See
"Marketing - Natural Gas" below.
6
Mountain Gas
Effective January 1, 1993, the Company acquired the stock of Mountain Gas
Resources, Inc. ("Mountain Gas") from Morgan Stanley Leveraged Equity Fund II,
L.P. for total consideration of approximately $168.2 million, including the
payment of certain transaction costs and the assumption and repayment of $35
million of long-term debt attributable to Mountain Gas.
Mountain Gas owns the Red Desert and Granger facilities, both located near the
Company's Lincoln Road gas processing plant and gathering system. The 22%
interest in the Granger facility previously not owned by Mountain Gas was
purchased by the Company in two separate transactions in November and December
1993 for an aggregate of $27.7 million. At the date of acquisition, the Red
Desert facility consisted of a cryogenic plant and the Granger plant consisted
of a refrigeration unit and a cryogenic unit. In December 1993, the Company
completed construction of an additional cryogenic processing plant at Granger,
at a total additional cost of approximately $4.8 million.
Black Lake
Effective January 1, 1993, the Company purchased the Black Lake gas processing
plant and related reserves ("Black Lake") from Nerco Oil & Gas, Inc. for
approximately $136.2 million. The acquisition included a 68.9% working interest
in the Black Lake field in Louisiana and a gas processing plant. To increase
the efficiency of Black Lake's processing capabilities, the Company installed a
cryogenic processing plant at a cost of approximately $4.1 million. The
cryogenic processing plant, which became fully operational in October 1994, has
decreased fuel usage and plant operating expenses, and also provides flexibility
to recover or reject ethane.
Westana Joint Venture
Effective August 1, 1993, the Company formed Westana, a general partnership,
with PanEnergy. Westana provides gas gathering and processing services in the
Anadarko Basin in Oklahoma and markets natural gas and NGLs for producers
connected to its system. The Company is the principal operator, with each
partner holding a 50% ownership interest.
The Company contributed its Chester gas processing plant and gathering system,
with a net book value of $13.8 million, to Westana. The Company also made
additional partnership contributions of $7.2 million through December 31, 1995,
which will be recouped through preferential distributions. In addition to the
assets contributed by the Company, Westana operates PanEnergy's 400 mile
gathering system and six compressor stations, which will be contributed to
Westana by PanEnergy. PanEnergy has received and accepted abandonment approval
by the Federal Energy Regulatory Commission ("FERC") and is now awaiting certain
clarification of the abandonment approval. Upon clarification from the FERC on
the abandonment approval, PanEnergy will contribute its gathering assets to
Westana. The Company expects the contribution of the PanEnergy assets will
occur in 1996.
Other
The Company continually monitors the economic performance of each of its
operating facilities to ensure that a desired cash flow objective is achieved.
If an operating facility is not generating desired cash flows or does not fit in
with the Company's strategic plans, the Company will explore various options,
such as consolidation with other Company-owned facilities, dismantlement, asset
swap or outright sale. In 1995, the Company sold the Waha Header and certain
non-strategic assets acquired in the Oasis acquisition and completed the
consolidation of its Lamont gathering system with the Chaney Dell system. The
Company anticipates completing the salvage of substantially all of the Lamont
processing plant assets by the end of the first quarter of 1996. In 1994, the
Company sold its Sligo plant, swapped its Pyote treating facilities for
gathering assets in Kansas, which were subsequently disposed of during the
second quarter of 1995, consolidated assets in the Powder River Basin and sold
its Walnut Bend gathering system. The Company anticipates that the salvage of
the Walnut Bend processing plant will be substantially completed by the end of
the third quarter of 1996. Commencing in March 1996, the Company and its joint
venture partner at the Lincoln Road gas plant temporarily suspended processing
operations at that plant and began processing the associated gas at the
Company's Granger facility. If volumes increase substantially beyond Granger's
capacity, the Lincoln Road plant might be re-started. The Company anticipates
that this consolidation will result in lower overall plant operating expenses
for the combined systems. In January 1996, Koch, which operates the Teddy
Roosevelt and Williston assets under a lease agreement, exercised its option to
purchase certain gas gathering assets located in North Dakota from the Company
and Williston. Proceeds from the sale of the gathering assets will be
approximately $2.4 million, of which the Company is entitled to receive $1.5
million. The closing on the sale is expected to occur on August 1, 1996, at
which time the operation of Williston and the Company's Teddy Roosevelt facility
will cease and any remaining assets will be salvaged.
7
MARKETING
Natural Gas
The Company markets residue gas produced at its plants and purchased from third
parties to end-users, local distribution companies ("LDCs"), pipelines and other
marketing companies throughout the United States. Historically, the Company's
gas marketing was an outgrowth of the Company's gas processing activities and
was directed towards selling gas processed at its plants to ensure their
efficient operation. As the Company expanded into new basins and the natural
gas industry became deregulated and offered more opportunity, the Company began
to increase its third-party gas marketing. Average gas sales increased to
1,572 MMcf per day for the year ended December 31, 1995 compared to 220 MMcf per
day for the year ended December 31, 1990, primarily as a result of increased
third-party sales and sales attributable to acquisitions and to the Katy
Facility, which began operations in 1994. The Company has continued to increase
sales to end-users and to achieve greater market penetration close to its
facilities while also expanding into new markets throughout the United States.
The Company sells gas under agreements with varying terms and conditions in
order to match seasonal and other changes in demand. Most of the Company's
current sales contracts are short-term, ranging from a few days to one year. At
December 31, 1995, the Company's commitment under long-term contracts, several
of which have an annual redetermination of prices and several of which are rebid
prior to expiration, was approximately 300 MMcf per day.
The Company intends to continue to expand its residue gas marketing and third-
party sales, particularly to industrial and commercial end-users. The Company's
marketing department has recently been restructured along more specialized lines
to include separate managers for national accounts, end-use sales and electric
power marketing. The Company has also expanded its marketing in areas beyond
its traditional gas supply centers (Houston and the Gulf Coast) to demand
centers, such as Chicago, New York and California. Third-party sales and
residue gas storage, combined with the stable supply from Company facilities,
enable the Company to respond quickly to changing market conditions and to take
advantage of seasonal price variations and peak demand periods.
The Company customarily stores residue gas in underground storage facilities to
ensure an adequate supply for long-term sales contracts and for resale during
periods when prices are favorable. In order to meet the peaking demand for
residue gas in certain markets, the Company constructed the Katy Facility. The
ability to withdraw gas from the Katy Facility on short notice positions the
Company to market residue gas to LDCs and other customers that need a reliable
yet variable supply of residue gas. The Katy Facility allows the Company to
bypass certain transportation bottlenecks and enhances flexibility in its
marketing operations. The complex utilizes a partially depleted natural gas
reservoir with 19 Bcf of working gas capacity and a pipeline header system,
currently connected to eleven pipelines, which has the capability to deliver up
to 400 MMcf per day of residue gas from the reservoir.
At December 31, 1995, the Company held approximately 12.8 Bcf of residue gas
inventory in underground storage at an average cost of $1.82 per Mcf ($1.65 per
MMBtu), primarily at the Katy Facility. At December 31, 1995, the Company had
hedging contracts in place for anticipated sales for approximately 12.5 Bcf of
stored gas at a weighted average price of $1.88 per MMBtu for the 1995-1996
winter heating season. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Liquidity and Capital Resources" and "Note
5 - Risk Management" to the Company's Consolidated Financial Statements
elsewhere in this Form 10-K.
In December 1993, the Company entered into a three-year winter-peaking gas
purchase and sales agreement with a major utility in East Texas which designates
the Katy Facility as the primary delivery point. Under the agreement, which was
amended in August 1994 to expire in March 1997, the utility has the right to
purchase, during each year of the contract, up to approximately 50 MMcf of
residue gas per day in November and March and approximately 140 MMcf of residue
gas per day in December, January and February, at the Houston Ship Channel Index
Price, determined daily, plus a demand charge. The agreement calls for a
minimum demand charge to be paid to the Company for each contract term, whether
or not delivery is taken. This minimum demand charge is calculated based upon
five Bcf of available storage during each fiscal year of the contract term.
In February 1995, the Company entered into a long-term firm storage and
transportation agreement with a St. Louis-based LDC. Under the agreement, the
Company has leased approximately three Bcf of storage capacity of the Katy
Facility to the LDC. The gas will principally serve local distribution
requirements of the LDC's customers in central Missouri.
8
During the year ended December 31, 1995, the Company sold residue gas to
approximately 370 end-users, pipelines, LDCs and other customers. No single
customer accounted for more than 3.5% of consolidated revenues for the year
ended December 31, 1995.
NGL Marketing
The Company markets NGLs (ethane, propane, iso-butane, normal butane, natural
gasoline, and condensate) produced at its plants and purchased from third
parties in the Rocky Mountain, Gulf Coast and Southwestern regions of the United
States. A majority of the Company's production of NGLs moves to the Gulf Coast
area, which is the largest NGL market in the United States. Through the
development of end-use markets and distribution capabilities, the Company seeks
to ensure that production from the plants moves on a reliable basis, avoiding
curtailment of production.
Consumption of NGLs is primarily determined by various end-user markets
including the petrochemical industry, the petroleum refining industry and the
retail and industrial fuel markets. As an example, the petrochemical industry
uses ethane, propane, normal butane and natural gasoline as feedstocks in the
production of ethylene, which is used in the production of various plastics
products. Over the last several years, the petrochemical industry has increased
its use of NGLs as a major feedstock. Further, various NGLs are used for home
heating and cooling, transportation and for certain agricultural applications.
Demand is primarily affected by price, seasonality and the economy.
The volatility of NGL prices in recent years has caused the Company to move to
short-term contracts, with no prices set on a firm basis for more than a 30-day
period. Although some existing contracts do commit the Company for periods as
long as a year, prices are redetermined on a market-related basis. The Company
leases NGL storage space at major trading locations near Houston and in central
Kansas in order to store products so that they can be sold at higher prices on a
seasonal basis. At December 31, 1995, approximately 15,800 MGal of NGLs were in
storage at an average cost of $.31 per gallon. The Company generally intends
that stored NGLs turn over on an annual basis. The Company from time to time
enters into futures contracts to hedge a portion of its share of condensate and
crude oil production. Although no such hedges were outstanding at December 31,
1995, the Company will continue to enter into futures contracts as management
deems appropriate. See also "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Liquidity and Capital Resources" and "Note
5 - Risk Management" to the Company's Consolidated Financial Statements
elsewhere in this Form 10-K.
For the year ended December 31, 1995, NGL sales averaged 2,890 MGal per day, an
increase from 630 MGal per day in 1990, primarily due to acquisitions during the
five-year period. Sales were made to approximately 170 different customers, and
no single customer accounted for more than 3% of the Company's consolidated
revenues for the year ended December 31, 1995. Revenues are also derived from
contractual marketing fees charged to some producers for NGL marketing services.
For the year ended December 31, 1995, such fees were less than 1% of the
Company's consolidated revenues.
PRODUCING PROPERTIES
Revenues derived from the Company's producing properties comprised approximately
2.6% of revenues for the year ended December 31, 1995. The producing properties
are primarily working interests in a unit operated by the Company comprising the
Black Lake field in Louisiana, which provides production to the Black Lake
plant, and 20 gas properties producing from the Smackover formation of the East
Texas Basin, which provide production to the Edgewood plant. The Company also
has working interests in the Powder River Basin in northeastern Wyoming, the
Sandwash Basin in northwestern Colorado, the Austin Chalk formation in southeast
Texas and the San Juan Basin in southwest Colorado. The Company also owns
various working interests in 13 wells in the Smackover formation through Redman
Smackover.
COMPETITION
The Company competes with other companies in the gathering, processing and
marketing business, both for supplies of natural gas and for customers to which
natural gas and NGLs are sold. 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 natural gas and NGL customers is primarily based upon
reliability and price of deliverable natural gas and NGLs. For customers that
have the capability of using alternative fuels, such as oil and coal, the
Company also competes based primarily on price against companies capable of
providing such alternative fuels. The Company's competitors for obtaining
additional gas supplies, for gathering and processing gas and for marketing gas
and NGLs include national and local gas gatherers, brokers,
9
marketers and distributors of various size, financial resources and experience.
In recent years, the Company has also experienced narrowing margins due to the
increasing availability of pricing information to the participants in the
natural gas industry.
REGULATION
The purchase and sale of natural gas and the fees received for gathering and
processing by the Company have generally not been subject to regulation, and
therefore, except as constrained by competitive factors, the Company has
considerable pricing flexibility. Many aspects of the gathering, processing,
marketing and transportation of natural gas and NGLs by the Company, however,
are subject to federal, state and local laws and regulations which can have a
significant impact upon the Company's overall operations.
As a processor and marketer of natural gas, the Company depends on the
transportation and storage services offered by various interstate and intrastate
pipeline companies for the delivery and sale of its own gas supplies as well as
those it processes and/or markets for others. Both the performance of
transportation and storage services by interstate pipelines, and the rates
charged for such services, are subject to the jurisdiction of the FERC under the
Natural Gas Act of 1938 (the "NGA") and the Natural Gas Policy Act of 1978 (the
"NGPA"). The availability of interstate transportation and storage service
necessary to enable the Company to make deliveries and/or sales of residue gas
can at times be pre-empted by other system users in accordance with FERC-
approved methods for allocating the system capacity of "open access" pipelines.
Moreover, the rates charged by pipelines for such services are often subject to
negotiation between shippers and the pipelines within certain FERC-established
parameters and will periodically vary depending upon individual system usage and
other factors. An inability to obtain transportation and/or storage services at
competitive rates can hinder the Company's processing and marketing operations
and/or affect its sales margins.
During the past ten years, the FERC has implemented a nondiscriminatory blanket
transportation program which initially authorized, and ultimately mandated,
interstate natural gas pipelines to perform "open access," self-implementing
(i.e., not generally requiring case-specific certificate authorization)
transportation services. Order Nos. 636, et seq., which constitute the FERC's
-------
most recent issuances in this program, promulgated regulations that
substantially restructure the services provided by interstate pipelines by
"unbundling" (i.e., separating) and separately pricing pipeline gathering,
transportation, storage and sales activities in an effort to enable non-pipeline
merchants to compete with pipelines for gas purchasers on an equal basis. These
regulations have largely been implemented by all interstate transporters
utilized by the Company (as well as by the Company's own non-major interstate
pipeline located in Wyoming) in numerous individual pipeline restructuring and
rate proceedings. The conversion of pipelines from natural gas merchants to
primarily transporters of gas through implementation of the FERC's open access
transportation and restructuring programs has caused the pipelines to incur
significant producer take-or-pay costs and other transition costs resulting from
their abandonment of gas purchasing and sales activities. The FERC has allowed,
and indicated in Order Nos. 636, et seq. that it will continue to allow, the
------
recovery of some or all of these and related costs from current shippers of gas.
Pipeline flow-through of many of these costs is subject to the outcome of
administrative and appellate proceedings in individual pipeline rate and
restructuring cases, and Order Nos. 636, et seq. themselves are currently the
------
subject of numerous petitions for appellate review presently pending in the
United States Court of Appeals for the District of Columbia Circuit. The outcome
of these proceedings could affect the Company's operations and the costs of
transporting and selling gas.
Pursuant to Section 1(b) of the NGA, production and gathering activities are
exempt from the FERC's jurisdiction; however, judicial precedent has held that
where gathering is performed largely in connection with the delivery of gas in
interstate commerce, such gathering can be considered merely an extension of the
jurisdictional transportation of such gas and thus subject to NGA rate
regulation itself. Recently, primarily as a result of the unbundling of
interstate pipeline gathering services required by Order Nos. 636, et seq., many
------
pipelines have sought FERC authorization to abandon gathering operations and
facilities previously held to be subject to the NGA. In response to those
requests, the FERC has established a general policy permitting the abandonments
but requiring a showing demonstrating that existing customers have been offered,
for a two-year period, continued service through the abandoned facilities at the
same rates and under the same terms as were previously offered by the pipeline.
The Company has been active in acquiring and/or operating natural gas gathering
facilities abandoned by interstate pipelines and, thus, certain of its
operations and acquisitions have been affected by this FERC policy. The policy
is currently being challenged at both agency and appellate levels, but at this
stage the outcome of such challenges is too speculative to predict.
INSURANCE AND OPERATIONAL RISKS
The Company is subject to various hazards which are inherent in the industry in
which it operates such as explosions, product spills, leaks and fires, each of
which could cause personal injury and loss of life, severe damage to and
destruction of property and equipment, and pollution or other environmental
damage, and may result in curtailment or suspension of operations at the
affected facility. The Company maintains physical damage, comprehensive general
liability, workers' compensation and business interruption insurance. Such
insurance is subject to deductibles that the Company considers reasonable. The
Company is not fully
10
insured against all risks in its business; however, the Company believes that
the coverage it maintains is adequate and consistent with other companies in the
industry. Consistent with insurance coverage typically available to the natural
gas industry, the Company's insurance policies do not provide coverage for
losses or liabilities relating to pollution, except for sudden and accidental
occurrences.
EMPLOYEES
At December 31, 1995, the Company employed 862 full-time employees, none of whom
was a union member. The Company considers relations with employees to be
excellent.
ITEM 3. LEGAL PROCEEDINGS
None.
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, 1995.
11
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
As of March 1, 1996, there were 25,773,051 shares of Common Stock outstanding
held by 423 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 closing sales prices as reported by the NYSE Composite Tape for the
quarterly periods indicated.
HIGH LOW
------ ------
1994
First Quarter........................................ $ 35 $ 26 1/8
Second Quarter....................................... 30 26
Third Quarter........................................ 28 1/2 18 1/2
Fourth Quarter....................................... 22 1/8 18 1/8
1995
First Quarter........................................ 22 1/8 16 3/4
Second Quarter....................................... 24 1/4 16 5/8
Third Quarter........................................ 18 1/4 15 1/2
Fourth Quarter....................................... $ 17 5/8 $ 15
The Company paid annual dividends on the Common Stock aggregating $.20 per share
during the years ended December 31, 1995 and 1994. The Company has declared a
dividend of $.05 per share of common stock for the quarter ending March 31, 1996
to holders of record as of March 29, 1996. Declarations of dividends on the
Common Stock are within the discretion of the Board of Directors. In addition,
the Company's ability to pay dividends is restricted by certain covenants in its
financing facilities, the most restrictive of which prohibits declaring or
paying dividends after December 31, 1995 that exceed, in the aggregate, the sum
of $10 million plus 50% of the Company's cumulative consolidated net income
earned after December 31, 1995 plus 50% of the net proceeds received by the
Company after December 31, 1995 from the sale of any equity securities. The
dividends declared in the fourth fiscal quarter of 1995, payable in 1996, are
excluded from this calculation. At December 31, 1995, this threshold amounted
to $10.0 million.
12
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected consolidated financial and operating
data for the Company. Certain prior year amounts have been reclassified to
conform to the presentation used in 1995. The data for the three years ended
December 31, 1995 should be read in conjunction with the Company's Consolidated
Financial Statements included elsewhere in this Form 10-K. The selected
consolidated financial data for the two years ended December 31, 1991 is derived
from the Company's historical Consolidated Financial Statements. See also Item
7 - "Management's Discussion and Analysis of Financial Condition and Results of
Operations."
Year Ended December 31,
-------------------------------------------------------------
1995 1994 1993 1992 1991
----------- ---------- ---------- ---------- ---------
(000s, except per share amounts and operating data)
STATEMENT OF OPERATIONS:
Revenues................................... $1,256,984 $1,063,489 $932,338 $600,116 $358,242
Gross profit............................... 75,211 72,556 92,012 88,192 58,152
Income (loss) before taxes................. (8,266) (a) 11,524 (b) 55,631 58,445 32,783
Provision (benefit) for income taxes....... (2,158) 4,160 17,529 18,757 11,933
Net income (loss).......................... (6,108) (a) 7,364 (b) 38,102 39,688 20,850
Earnings (loss) per share of common
stock.................................... (.84) (.19) 1.25 1.43 .94
CASH FLOW DATA:............................
Net cash provided by operating activities.. 86,373 31,866 107,116 96,655 36,228
Capital expenditures....................... 78,521 100,540 492,328 67,021 234,124
BALANCE SHEET DATA.........................
(at period end):
Total assets............................... 1,193,997 1,167,362 1,114,748 582,188 552,321
Long-term debt............................. 454,500 418,000 547,000 157,000 216,050
Stockholders' equity....................... 371,909 436,683 314,387 287,021 221,389
Dividends declared per share of common
stock.................................... $ .20 $ .20 $ .20 $ .20 $ .15
OPERATING DATA:............................
Average gas sales (MMcf/D)................. 1,572 1,097 755 442 310
Average NGL sales (MGal/D)................. 2,890 2,970 2,941 2,400 1,097
Average gas volumes gathered (MMcf/D)...... 1,020 934 804 669 408
Facility capacity (MMcf/D)................. 1,907 1,560 1,586 1,177 1,183
Average gas prices ($/Mcf)................. 1.53 1.77 2.02 1.72 1.59
Average NGL prices ($/Gal)................. .31 .28 .31 .32 .36
(a) In 1995, the Company adopted Statement of Financial Accounting Standards
("SFAS") No.121,"Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed of," which resulted in the recognition of a
non-cash loss of $17.6 million. Also, the Company implemented a cost reduction
program to reduce operating and selling and administrative expenses. As a result
of this program, a $2.1 million restructuring charge was incurred, primarily
related to employee severance costs.
(b) In December 1993, a fire at the Granger facility's NGL tank farm required
the facility to be shut down for one week. The new cryogenic processing plant as
well as the smaller existing cryogenic unit were also damaged. Construction of a
new tank farm and repairs to the cryogenic units were completed and fully
operational in August 1994. Claims for physical damage to the Company's
facilities totaled approximately $6.7 million. In addition, the Company
recorded, as other revenue, $3.3 million relating to lost income covered under
its business interruption insurance policy for the year ended December 31, 1994.
As of December 31, 1995, the Company had resolved substantially all remaining
issues and collected all remaining insurance proceeds. The total reimbursements
the Company received under its insurance policies were $6.6 million for physical
damage and $3.9 million related to business interruption.
13
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion and analysis relates to factors which have affected the
consolidated financial condition and results of operations of the Company for
the three years ended December 31, 1995. Certain prior year amounts have been
reclassified to conform to the presentation used in 1995. Reference should also
be made to the Company's Consolidated Financial Statements and related Notes
thereto and the Selected Financial Data included elsewhere in this Form 10-K.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1995 COMPARED TO YEAR ENDED DECEMBER 31, 1994 (000S,
EXCEPT PER SHARE AMOUNTS AND OPERATING DATA)
Year Ended
December 31, Percent
-------------------------
1995 1994 Change
------------ ---------- ------
FINANCIAL RESULTS:
Revenues................................... $ 1,256,984 $ 1,063,489 18.2
Gross profit............................... 75,211 72,556 3.7
Net (loss) income.......................... (6,108) 7,364 (182.9)
Loss per share of common stock............. (.84) (.19) (342.1)
Net cash provided by operating activities.. $ 86,373 $ 31,866 171.1
OPERATING DATA:
Average gas sales (MMcf/D)................. 1,572 1,097 43.3
Average NGL sales (MGal/D)................. 2,890 2,970 (2.7)
Average gas prices ($/Mcf)................. 1.53 1.77 (13.6)
Average NGL prices ($/Gal)................. .31 .28 10.7
Net income decreased $13.5 million and net cash provided by operating activities
increased $54.5 million for the year ended December 31, 1995 compared to 1994.
The decrease in net income for the year was primarily due to a $17.6 million
pre-tax impairment loss recorded in connection with the adoption of SFAS No.
121,"Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed of," and a $2.1 million pre-tax restructuring charge the
Company recorded in May 1995 relating to its cost reduction program. In
addition, net income was adversely affected by higher product purchase costs
associated with the Company's third-party residue gas sales and increased
depreciation, depletion and amortization expense and interest expense, partially
offset by higher residue gas volumes sold and higher NGL prices.
Revenues from the sale of residue gas increased approximately $168.5 million for
the year ended December 31, 1995 compared to 1994. Average gas sales volumes
increased 475 MMcf per day to 1,572 MMcf per day for the year ended December 31,
1995 compared to 1994, largely due to an increase of approximately 460 MMcf per
day in the sale of residue gas purchased from third parties. Average gas prices
decreased $.24 per Mcf to $1.53 per Mcf for the year ended December 31, 1995
compared to 1994. The effect of the decrease in residue gas prices on the
Company's net margin from equity production was partially offset by the
Company's futures positions; approximately $10.0 million of gain was recognized
in the year ended December 31, 1995 related to such contracts. The Company has
entered into futures positions for a portion of its equity gas for 1996. See
further discussion at "Forward Looking Information-Hedging."
Revenues from the sale of NGLs increased approximately $22.4 million for the
year ended December 31, 1995 compared to 1994. Average NGL sales volumes
remained relatively constant at 2,890 MGal per day and average NGL prices
increased $.03 per gallon to $.31 per gallon for the year ended December 31,
1995 compared to 1994.
Processing, transportation and storage revenues increased $6.3 million for the
year ended December 31, 1995 compared to 1994. Approximately $3.6 million of the
increase was due to greater NGL revenues from the Company's Giddings system and
increased treating revenue, primarily from gathering systems acquired in
December 1994. The remaining increase was primarily due to a long-term firm
storage and transportation agreement at the Katy Facility that the Company
entered into in February 1995.
14
Other net revenue decreased $3.7 million for the year ended December 31, 1995
compared to 1994. The difference was primarily attributable to a $3.3 million
insurance recovery recorded in 1994 for business losses associated with the
December 1993 fire at the Company's Granger facility.
The increase in product purchases corresponds to the increase in third-party
residue gas sales. Combined product purchases as a percentage of residue gas
and NGL sales increased two percentage points to 86% for the year ended
December 31, 1995 compared to 1994. The rising gas purchase percentage is a
continuing trend based upon the growth of third-party sales, which typically
have lower margins than sales of the Company's equity production. Until
recently, the Company had experienced narrowing margins related to third-party
sales due to the increasing availability of pricing information in the natural
gas industry. The Company believes by targeting end-use markets, these margins
will be stabilized. However, there is no assurance that the Company will be
successful in capturing these markets.
Plant operating expense increased $2.5 million for the year ended December 31,
1995. The increase was attributable to assets purchased in the Oasis
acquisition in December 1994, primarily for property taxes, and taxes on higher
levels of inventory held at the Katy Facility, partially offset by cost savings
resulting from the cost reduction plan initiated in May 1995.
Selling and administrative expense decreased $3.0 million, primarily due to the
cost reduction plan implemented in May 1995.
Depreciation, depletion and amortization increased $1.8 million for the year
ended December 31, 1995 compared to the prior year period. The increase was
primarily attributable to the Oasis assets, additional depletion related to the
Company's oil and gas production and various plant upgrades and equipment
additions in 1995.
Interest expense increased $5.7 million for the year ended December 31, 1995
compared to 1994, due to an increase in the Company's average borrowing rate
from 6.6% to 7.5% per annum and higher average debt outstanding during 1995,
primarily due to the redemption of the 7.25% Cumulative Perpetual Convertible
Preferred Stock.
The provision for income taxes for the year ended December 31, 1995 includes a
$300,000 adjustment to reflect management's estimate of deferred taxes.
YEAR ENDED DECEMBER 31, 1994 COMPARED TO YEAR ENDED DECEMBER 31, 1993 (000s,
EXCEPT PER SHARE AMOUNTS AND OPERATING DATA)
Year Ended
December 31, Percent
-------------------------
1994 1993 Change
------------ --------- -------
FINANCIAL RESULTS:
Revenues................................... $ 1,063,489 $ 932,338 14.1
Gross profit............................... 72,556 92,012 (21.1)
Net income................................. 7,364 38,102 (80.7)
Earnings per share of common stock......... (.19) 1.25 (115.2)
Net cash provided by operating activities.. $ 31,866 $ 107,116 (70.3)
OPERATING DATA:
Average gas sales (MMcf/D)................. 1,097 755 45.3
Average NGL sales (MGal/D)................. 2,970 2,941 1.0
Average gas prices ($/Mcf)................. 1.77 2.02 (12.4)
Average NGL prices ($/Gal)................. .28 .31 (9.7)
Net income decreased $30.7 million and net cash provided by operating activities
decreased $75.3 million for the year ended December 31, 1994 compared to the
same period in 1993. Overall, throughput and sales volumes at the Company's
facilities remained comparable to historical levels. The Company's decrease in
net income and net cash provided by operating activities was primarily
attributable to a decline in NGL and residue gas prices and higher interest,
selling and administrative and depreciation, depletion and amortization costs
associated with the Company's 1993 acquisitions of Black Lake and Mountain Gas,
along with the completion of the Katy Facility construction. In addition,
because of lower demand and lower than expected prices, the Katy Facility did
not generate significant revenue. As a result, revenues from the Katy Facility
in 1994 did not fully offset related depreciation, depletion and amortization,
interest and operating costs.
15
Revenues from the sale of residue gas increased approximately $144.8 million for
the year ended December 31, 1994 compared to the same period in 1993, as a
volume increase of 342 MMcf per day was somewhat offset by a decrease in average
residue gas sales prices of $.25 per Mcf. Approximately 300 MMcf per day of the
volume increase was attributable to an increase in the sale of residue gas
purchased from third-parties, primarily resulting from the acquisition of
Citizens National Gas Company assets in the third quarter of 1993. The remaining
volume increase was the result of increased production volumes at the Company's
facilities, primarily due to the Mountain Gas and Black Lake acquisitions, new
well connect activities and consolidations with smaller gathering systems.
Revenues from the sale of NGLs decreased approximately $24.5 million for the
year ended December 31, 1994 compared to 1993, as a volume increase of
approximately 30 MGal per day was more than offset by a $.03 per gallon decrease
in the average NGL sales price. Approximately 22 MGal per day of the volume
increase was attributable to an increase in the sale of NGLs purchased from
third-parties. The remaining volume increase was primarily attributable to the
acquisitions of Mountain Gas and Black Lake, new well connect activity and
consolidations with smaller gathering systems. This volume increase was somewhat
offset by unfavorable economics of ethane and propane extraction in the first
quarter of 1994 and by limited NGL volumes at the Granger facility, primarily as
a result of the December 1993 fire. The curtailment of production while plant
improvements were completed during the third quarter of 1994 at Black Lake also
contributed to lower volumes.
Processing, transportation and storage revenues increased $9.4 million for the
year ended December 31, 1994 compared to the same period in 1993. The increase
was due to additional gathering revenue associated with the Company's Granger
gathering system acquired in the Mountain Gas acquisition in July 1993,
increased gathering revenue at the Company's Lincoln Road facility and the
recognition of demand fees associated with a winter-peaking gas purchase and
sales contract at the Katy Facility during 1994.
Other net revenue increased $1.4 million for the year ended December 31, 1994
compared to the same period in 1993. For the year ended December 31, 1994, the
Company accrued approximately $3.3 million as an amount to be recovered under
its business interruption insurance policy for business losses associated with
the December 1993 fire at the Company's Granger facility and approximately $1.4
million in rate refunds from a pipeline company. These 1994 recoveries were
somewhat offset by a $2.6 million gain recorded as a result of the termination
of interest rate swap agreements in 1993.
Historically, product purchases as a percentage of residue gas and NGL sales
from the Company's plant production have approximated 70%. Product purchases as
a percentage of residue gas and NGL sales from third-party purchases were
substantially higher in 1994 and approximated 95%. Total product purchases as a
percentage of residue gas and NGL sales increased approximately 2.5 percentage
points to 84% for the year ended December 31, 1994 compared to the same period
in 1993. The increase in the Company's combined percentage was primarily due to
an increasing proportion of 1994 residue gas sales revenues resulting from
products purchased from third parties.
Plant operating expense and oil and gas exploration and production costs
increased approximately $6.1 million and $2.2 million, respectively, for the
year ended December 31, 1994 compared to the same period in 1993. The increase
in plant operating expense was primarily due to the additional operating costs
associated with three gas processing facilities acquired from Mountain Gas and
Black Lake in July 1993 and the Katy Facility, which commenced operations in
February 1994. The oil and gas exploration and production cost increase resulted
primarily from costs associated with producing properties acquired in the Black
Lake acquisition.
Selling and administrative expense increased approximately $5.7 million for the
year ended December 31, 1994 compared to the same period in 1993, primarily due
to administrative expenses necessitated by the 1993 acquisitions, an overall
increase in insurance expenditures and a reduction in overhead capitalized to
the Company's construction projects.
Depreciation, depletion and amortization expense increased approximately $19.6
million for the year ended December 31, 1994 compared to the same period in
1993. This increase was primarily due to the acquisitions of Mountain Gas and
Black Lake in July 1993 and the commencement of Katy Facility operations in
February 1994, and was partially offset by lower depreciation and depletion
expense resulting from the addition of recoverable reserves at Black Lake and
Edgewood during 1994.
Interest expense increased approximately $19.0 million for the year ended
December 31, 1994 compared to the same period in 1993, primarily due to
additional borrowings necessitated by the Mountain Gas and Black Lake
acquisitions, a reduction in the amount of interest capitalized to the Katy
Facility and an increase in the Company's variable borrowing rate.
16
LIQUIDITY AND CAPITAL RESOURCES
The Company's sources of liquidity and capital resources historically have been
net cash provided by operating activities, funds available under its financing
facilities and proceeds from offerings of equity securities. In the past, these
sources have been sufficient to meet the needs and finance the growth of the
Company's business. The Company can give no assurance that the historical
sources of liquidity and capital resources will be available for future
development and acquisition projects, and it may be required to investigate
alternative financing sources. Net cash provided by operating activities has
been primarily affected by product prices, the Company's success in increasing
the number and efficiency of its facilities and the volumes of natural gas
processed by such facilities, as well as the margin on third-party residue gas
purchased for resale. The Company's continued growth will be dependent upon
success in the areas of marketing, additions to dedicated plant reserves,
acquisitions and new project development.
The Company believes that the amounts available to be borrowed under the
Revolving Credit Facility, together with cash provided by operating activities,
will provide it with sufficient financing to connect new reserves, maintain its
existing facilities and complete its current capital improvement projects. The
Company also believes that cash provided by operating activities will be
sufficient to meet its debt service and preferred stock dividend requirements.
The Company's sources and uses of funds for the year ended December 31, 1995 are
summarized as follows (000s):
SOURCES OF FUNDS:
Borrowings under long-term debt agreements..... $ 717,400
Net cash provided by operating activities...... 86,373
Other.......................................... 13,445
-----------
Total sources of funds......................... $ 817,218
===========
USES OF FUNDS:
Payments related to long-term debt agreements.. $ 682,784
Capital investments............................ 78,521
Redemption of the 7.25% Cumulative Senior
Perpetual Convertible Preferred Stock 42,030
Payment of preferred dividends................. 11,643
Payment of common stock dividends.............. 5,153
-----------
Total uses of funds............................ $ 820,131
===========
Additional sources of liquidity available to the Company are volumes of residue
gas and NGLs in storage facilities. The Company stores residue gas and NGLs
primarily to ensure an adequate supply for long-term sales contracts and for
resale during periods when prices are favorable. The Company held residue gas
in storage for such purposes of approximately 12.8 Bcf at an average cost of
$1.82 per Mcf ($1.65 per MMBtu) at December 31, 1995 as compared to 21.9 Bcf at
an average cost of $2.16 per Mcf ($1.94 per MMBtu) at December 31, 1994,
primarily at the Katy Facility. The Company also held NGLs in storage of 15,816
MGal at an average cost of $.31 per gallon and 11,600 MGal at an average cost of
$.30 per gallon at December 31, 1995 and December 31, 1994, respectively, at
various third party storage facilities. At December 31, 1995, the Company had
hedging contracts in place for anticipated sales for approximately 12.5 Bcf of
stored gas at a weighted average price of $1.88 per MMBtu for the 1995-1996
winter heating season.
As of December 31, 1995, the Company had shelf registrations available providing
for the sale of up to $200 million of debt securities and preferred stock and up
to four million shares of common stock. On February 13, 1996, the Company filed
a registration statement registering an additional $100 million of debt
securities or preferred or common stock, which the Company believes will be
declared effective in April 1996.
The Company has been successful overall in replacing production with new
reserves. However, volumes of natural gas dedicated to some of the Company's
plants have declined in recent years because additions to dedicated plant
reserves have not fully offset production. In 1995, including the reserves
associated with Westana Gathering Company ("Westana") and 1995 acquisitions, the
Company connected new reserves to its gathering systems to replace approximately
94% of 1995 production. On a Company-wide
17
basis, dedicated reserves, including certain proved undeveloped properties and
revisions to previous estimates, decreased from 2.3 Tcf as of December 31, 1994
(as revised) to approximately 2.1 Tcf at December 31, 1995. The decrease is
primarily due to decreased drilling in all areas in which the Company operates
and declines in reserves at the Company's Black Lake field.
In May 1995, the Company redeemed all of the issued and outstanding shares of
its 7.25% Cumulative Senior Perpetual Convertible Preferred Stock (liquidation
preference of $40 million) pursuant to the provisions of the Certificate of
Designation relating to such preferred stock, at an aggregate redemption price
of approximately $42.0 million.
Risk Management Activities
The Company's policy is to utilize risk management tools primarily to reduce
commodity price risk for its equity production and to lock in profit margins for
its storage and marketing activities. It is the Company's objective to maintain
a balanced portfolio of financial exposure between physical obligations (fixed
price purchase and sales, storage inventories) and related financial instruments
(futures, swaps, and options positions). This effectively allows the Company to
fix its total margin because gains or losses in the physical market are offset
by corresponding losses or gains in the financial instruments market.
Hedging and related activities may expose the Company to the risk of financial
loss in certain circumstances, including instances when (i) production is 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 over-the-
counter ("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.
In 1993, the Board of Directors adopted its Natural Gas Futures Trading
Procedures and created a committee of officers to oversee the Company's risk
management activities. As an additional control, the Company has developed
information systems that allow daily monitoring of its risk management
activities and its exposure related to futures, swaps and options positions
resulting from changes in the market.
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
and the Kansas City Board of Trade and through OTC swaps with creditworthy
counterparties consisting primarily of financial institutions and other natural
gas companies. The Company conducts its standard credit review of OTC
counterparties and has agreements with such parties which contain collateral
requirements. OTC exposure is marked to market daily for the credit review
process. The Company generally uses standardized swap agreements which allow for
offset of positive and negative exposures.
Gains and losses on hedges of product inventory are included in the carrying
amount of the inventory and are ultimately recognized in residue and NGL sales
when the related inventory is sold. Gains and losses related to qualifying
hedges, as defined by SFAS No. 80, "Accounting for Futures Contracts", of firm
commitments or anticipated transactions are recognized in residue and NGL sales
when the hedged physical transaction occurs. The $1.9 million of losses deferred
in inventory at December 31, 1995 were recognized in January 1996 and were more
than offset by margins from the Company's related forward fixed price hedges and
physical sales.
As of December 31, 1995, the Company held a notional quantity of approximately
330 Bcf of natural gas futures, swaps, and options extending from January 1996
to February 1998. This was comprised of approximately 37 Bcf long and 31 Bcf
short of exchange-traded futures and 126 long and 136 short Bcf of OTC swaps and
options. As of December 31, 1994, the Company held a notional quantity of
approximately 210 Bcf of futures, swaps, and options extending through December
1997. This was comprised of approximately 34 Bcf long and 58 Bcf short of
exchange traded futures and 56 long and 62 short Bcf of OTC swaps and options.
The Company enters into speculative futures trades on a very limited basis for
purposes which include testing of hedging techniques. Company procedures contain
strict guidelines for such trading including predetermined stop-loss
requirements and net open positions limits (currently, a total position of 100
net contracts long or short). Speculative futures positions are marked to market
at the end of each accounting period and any gain or loss is recognized in
income for that period. Net gains from such speculative activities for the year
ended December 31, 1995 were not material. See further discussion of hedging
activities at
18
"Liquidity and Capital Resources - Forward Looking Information" and discussion
of other hedging activities at "Interest Rate Swaps."
Capital Investment Program
Between January 1, 1993 and December 31, 1995, the Company expended
approximately $672 million on new projects and acquisitions. For the years ended
December 31, 1995, 1994 and 1993 the Company expended $79 million, $101 million
and $492 million, respectively, on acquisitions, the construction of the Katy
Facility, connection of new reserves, the acquisition of consolidating assets
for existing systems and upgrades to existing and newly acquired facilities.
Capital expenditures related to existing operations are expected to be
approximately $76.1 million during 1996 consisting of the following: capital
expenditures related to gathering, processing and pipeline assets are expected
to be $63.2 million, of which $47.6 million will be used for new connects,
system expansions and asset consolidations and $15.6 million for maintaining
existing facilities. The Company expects capital expenditures on the Katy Gas
Storage Facility ("Katy Facility"), exploration and production activities and
miscellaneous items to be $4.8 million, $3.8 million and $4.3 million,
respectively.
Depending on the timing of the Company's future projects, it may be required to
seek additional sources of capital. The Company's ability to secure such
capital is restricted by its credit facilities, although it may request
additional borrowing capacity from the banks, seek waivers from the banks to
permit it to borrow funds from third parties, seek replacement credit facilities
from other lenders or issue additional equity securities. While the Company
believes that it would be able to secure additional financing, if required, no
assurance can be given that it will be able to do so or as to the terms of any
such financing.
Financing Facilities
Revolving Credit Facility. The Company's variable rate Revolving Credit
Facility, as restated on September 2, 1994 and subsequently amended, with a
syndicate of eight banks, provides for a maximum borrowing base of $300 million,
of which $137.5 million was outstanding at December 31, 1995. If the facility
is not renewed, its commitment period will terminate on October 1, 1997. Any
outstanding balance thereunder at such time will convert to a three-year term
loan, which shall be payable in 12 equal quarterly installments, commencing
January 1, 1998. The Revolving Credit Facility bears interest, at the Company's
option, at certain spreads over the Eurodollar rate, at the Federal Funds rate
plus .50%, or at the agent bank's prime rate. The interest rate spreads are
adjusted based on the Company's debt to capitalization ratio. At December 31,
1995, the spread was 1.25% over the Eurodollar rate, resulting in an interest
rate of 7.21%.
The Company pays a commitment fee on the unused commitment ranging from .15% to
.375% based on the debt to capitalization ratio. At December 31, 1995, the
Company's debt to capitalization ratio was .58 to 1 resulting in a commitment
fee rate of .375%.
Term Loan Facility. The Company also has a Term Loan Facility with four banks
for $25 million which bears interest at 9.87%. Payments on the Term Loan
Facility of $12.5 million are due in September 1996 and September 1997,
respectively. The Company intends to finance the $12.5 million payment due in
1996 through amounts available under the Revolving Credit Facility. The
agreements governing the Company's Revolving Credit and Term Loan Facilities
(the "Credit Facilities Agreement") contain certain mandatory prepayment terms.
If funded debt of the Company, which has a final maturity on or before October
1, 2000, exceeds four times (4.0 to 1.0) the sum of the Company's last four
quarters' cash flow (as defined in the agreement) less preferred stock dividends
projected to be paid during the next four quarters, the overage must be repaid
in no more than six monthly payments, commencing 90 days from notification.
This mandatory prepayment threshold will be reduced to 3.5 to 1.0 at September
1, 1998. At December 31, 1995, taking into account all the covenants contained
in the Credit Facilities Agreement, the Company had approximately $50 million
of available borrowing capacity.
The Term Loan and Revolving Credit Facilities are unsecured. Pursuant to the
Credit Facilities Agreement, the Company is required to maintain a current ratio
(as defined therein) of at least 1.0 to 1.0, a minimum tangible net worth equal
to the sum of $345.0 million plus 50% of consolidated net income earned after
June 30, 1995 plus 75% of the net proceeds received after June 30, 1995 from the
sale of equity securities, a debt to capitalization ratio (as defined therein)
of no more than 60% through October 31, 1996 and 55% thereafter, and an EBITDA
to interest ratio of not less than 3.00 to 1.0 through October 31, 1996, 3.25 to
1.0 from November 1, 1996 through October 31, 1997 and 3.75 to 1.0 thereafter.
The Company is prohibited from declaring or paying dividends on or after
December 31, 1995 that in the aggregate exceed the sum of $10 million plus 50%
of consolidated net income earned after December 31, 1995 plus 50% of the
cumulative net proceeds received by the Company after December 31, 1995 from the
sale of any equity securities. The dividends declared in the fourth fiscal
quarter of 1995, payable in 1996, are excluded from
19
this calculation. At December 31, 1995, $10 million was available under this
limitation, which is sufficient to pay required preferred stock dividends in
1996. The Company generally utilizes excess daily funds to reduce any
outstanding revolving credit balances and associated interest expense and it
intends to continue such practice. The $5.8 million cash balance at December 31,
1995 is an overnight investment necessitated by the timing of cash receipts.
Master Shelf Agreement. In December 1991, the Company entered into a Master
Shelf Agreement (the "Master Shelf") with The Prudential Insurance Company of
America ("Prudential") pursuant to which Prudential agreed to quote, from time-
to-time, an interest rate at which Prudential or its nominee would be willing to
purchase up to $100 million of the Company's senior promissory notes (the
"Master Notes"). Any such Master Notes will mature in no more than 12 years,
with an average life not in excess of 10 years, and are unsecured. The Master
Shelf contains certain financial covenants which substantially conform with
those contained in the Revolving Credit Facility, as restated and amended. In
July 1993 and July 1995, Prudential and the Company amended the Master Shelf to
provide for additional borrowing capacity (for a total borrowing capacity of
$200 million) and to extend the term of the Master Shelf to October 31, 1995.
The Master Shelf Agreement, as restated and amended, is fully utilized, as
indicated in the following table (000s):
Interest Final
Issue Date Amount Rate Maturity Principal Payments Due
- --------------------- ------- --------- ------------------- --------------------------------------------
October 27, 1992 $25,000 7.51% October 27, 2000 $8,333 each on October 27, 1998 through 2000
October 27, 1992 25,000 7.99% October 27, 2003 $8,333 each on October 27, 2001 through 2003
September 22, 1993 25,000 6.77% September 22, 2003 single payment at maturity
December 27, 1993 25,000 7.23% December 27, 2003 single payment at maturity
October 27, 1994 25,000 9.05% October 27, 2001 single payment at maturity
October 27, 1994 25,000 9.24% October 27, 2004 single payment at maturity
July 28, 1995 50,000 7.61% July 28, 2007 10,000 each on July 28, 2003 through 2007
-------
$200,000
========
1993 Senior Notes. On April 28, 1993 the Company sold $50 million of 7.65%
Senior Notes due 2003 to a group of insurance companies. Annual principal
payments of $7.1 million on the 1993 Senior Notes are due on April 30 of each
year from 1997 through 2002, with any remaining principal and interest
outstanding due on April 30, 2003. The 1993 Senior Notes contain certain
financial covenants that substantially conform with those contained in the
Master Shelf Agreement, as restated and amended.
1995 Senior Notes. The Company sold $42 million of 1995 Senior Notes to a group
of insurance companies in the fourth quarter of 1995, with an interest rate of
8.16% per annum and principal due in a single payment in December 2005. The 1995
Senior Notes contain certain financial covenants that conform with those
contained in the Master Shelf Agreement, as restated and amended. The Company
used the net proceeds from the sale to reduce borrowings under the Revolving
Credit Facility.
Receivables Facility. In April 1995, the Company entered into an agreement with
Receivables Capital Corporation ("RCC"), as purchaser, and Bank of America
National Trust and Savings Association ("BA"), as agent, pursuant to which the
Company will sell to RCC at face value on a revolving basis an undivided
interest in certain of the Company's trade receivables. As part of the sale, the
Company granted to RCC a security interest in such receivables. The Company may
sell up to $75 million of trade receivables under the Receivables Facility, at a
rate equal to RCC's commercial paper rate plus .375%, of which $75 million was
funded at a rate of 6.3% as of December 31, 1995. The Receivables Facility has a
364-day term and contains financial covenants similar to those in the Credit
Facilities Agreement, as restated and amended, along with certain covenants
regarding the quality of the trade receivables pool.
On September 2, 1994, in anticipation of entering into the Receivables Facility,
BA entered in a Master Note Agreement (the "Short-Term Note") with the Company
and advanced the Company $75 million at the Eurodollar rate plus .50%, which
resulted in an interest rate of 6.56% per annum at June 30, 1995. The Company
used the $75 million drawn on the Receivables Facility to repay the Short-Term
Note, which was then canceled.
COVENANT COMPLIANCE. At December 31, 1995, the Company was in compliance with
all covenants in its loan agreements.
INTEREST RATE SWAP AGREEMENTS. Historically, the Company has entered into
interest rate swap agreements to manage exposure to changes in interest rates.
The transactions generally involve the exchange of fixed and floating interest
payment obligations or the exchange of foreign and U.S. currencies, without the
exchange of the underlying principal amounts. The net effect of interest
20
rate swap activity is reflected as an increase or decrease in interest expense.
Any gains on termination of interest rate swap agreements and the effects of
foreign currency positions that were marked to market are included in other
income. At December 31, 1995 and 1994, the total notional principal amount of
outstanding interest rate swap agreements was $0 and $50 million, respectively.
In addition to the financial risk, which will vary during the life of these swap
agreements in relation to the maturity of the underlying debt and market
interest rates, the Company is subject to credit risk exposure from
nonperformance of the counterparties to the swap agreements.
In anticipation of issuing the 1995 Senior Notes in the fourth quarter of 1995,
the Company entered into an interest rate lock on a notional amount of $50
million, linked to the ten-year U.S. Treasury Bill rate, with a creditworthy
counterparty to hedge against the risk of rising interest rates while it
completed the 1995 Senior Notes placement. At the time the Company terminated
the rate lock, interest rates had decreased, which resulted in the realization
of a $390,000 loss. The Company considered the loss to be a cost of obtaining
the privately placed debt and is therefore amortizing it over the ten-year term
of the 1995 Senior Notes.
The following table summarizes the results of the Company's interest rate swap
and foreign currency positions for each of the three years in the period ended
December 31, 1995 (000s):
1995 1994 1993
----- ------ -------
Net (increase) decrease to interest expense........... $ 358 $ (932) $ 1,769
===== ====== =======
Interest rate swap losses capitalized................. $ 390 $ - $ -
===== ====== =======
Gains on swap termination............................. $ - $ - $ 2,590
===== ====== =======
Losses on foreign currency positions.................. $ - $ (361) $(1,175)
===== ====== =======
Environmental
The construction and operation of the Company's gathering lines, plants and
other facilities used for the gathering, transporting, processing, treating or
storing of residue gas and NGLs are subject to federal, state and local
environmental laws and regulations, including those that can impose obligations
to clean up hazardous substances at the Company's facilities or at facilities to
which the Company sends wastes for disposal. In most instances, the applicable
regulatory requirements relate to water and air pollution control or solid waste
management procedures. The Company employs six environmental engineers to
monitor environmental compliance and potential liabilities at its facilities.
Prior to consummating any major acquisition, the Company's environmental
engineers perform audits on the facilities to be acquired. In addition, on an
ongoing basis, the environmental engineers perform systematic environmental
assessments of the Company's existing facilities. The Company believes that it
is in substantial compliance with applicable material environmental laws and
regulations. Environmental regulation can increase the cost of planning,
designing, constructing and operating the Company's facilities. The Company
believes that the costs for compliance with current environmental laws and
regulations have not had and will not have a material effect on the Company's
financial position or results of operation.
In 1990, the Congress enacted the Clean Air Act Amendments of 1990 (the "Clean
Air Act") which impose more stringent standards on emissions of certain
pollutants and require the permitting of certain existing air emissions sources.
Many of the regulations have not yet been promulgated and until their
promulgation, the Company cannot make a final assessment of the impact of the
Clean Air Act. However, based upon its preliminary review of the proposed
regulations, the Company does not anticipate that compliance with the Clean Air
Act will require any material capital expenditures, although it will increase
permitting costs in 1996 and may increase certain operating costs on an ongoing
basis. The Company does not believe that such cost increases will have a
material effect on the Company's financial position or results of operations.
The Company believes that it is reasonably likely that the trend in
environmental legislation and regulation will continue to be towards stricter
standards. The Company is unaware of future environmental standards that are
reasonably likely to be adopted that will have a material effect on the
Company's financial position or results of operations, but it cannot rule out
that possibility.
The Company is in the process of voluntarily cleaning up substances at
facilities that it operates. In addition, the former owner of certain facilities
that the Company acquired in 1992 is conducting remediation at those facilities
pursuant to contractual obligations. The Company's expenditures for
environmental evaluation and remediation at existing facilities have not been
21
significant in relation to the results of operations of the Company and totaled
approximately $1.3 million for the year ended December 31, 1995. For the year
ended December 31, 1995, the Company paid an aggregate of approximately $757,000
in air emissions fees to the states in which it operates. Although the Company
anticipates that such environmental expenses will increase over time, the
Company does not believe that such increases will have a material effect on the
Company's financial position or results of operations.
FORWARD LOOKING INFORMATION
The Company has developed a three-part business plan to increase profitability
through continued growth of the Company's core businesses. The Company plans to
expand its marketing activities, acquire or develop gas gathering and processing
assets that meet the Company's target rates of return and increase the
efficiency of its existing facilities.
Marketing
The Company's existing natural gas and NGL marketing was a by-product of the
Company's processing activities and was directed towards selling natural gas and
NGLs processed at its plants to ensure their efficient operation. As the Company
expanded into new basins and the natural gas industry became deregulated, the
Company began to increase its third-party marketing. The Company believes that
the knowledge and understanding gained through its gas gathering and processing
operations coupled with its understanding of the pipeline network are the basis
for its success in marketing natural gas and NGLs. Average daily gas sales
increased to 1,572 MMcf per day and NGL sales increased to 2,890 MGal per day
for the year ended December 31, 1995 compared to 220 MMcf and 630 MGal,
respectively, for the year ended December 31, 1990, a 615% and 359% increase,
respectively.
Natural Gas
The Company plans to expand its gas marketing by (i) targeting special needs of
end-users willing to pay higher margins, (ii) increasing its use of the Katy
Facility and (iii) entering the recently deregulated electric power marketing
sector. The Company's marketing department has recently been restructured along
more specialized lines to include separate managers for national accounts, end-
use sales and electric power marketing. In 1996, the Company plans to hire four
experienced marketers who will primarily be involved in seeking national
accounts with companies having multiple facilities throughout the country. There
is no assurance that the Company will be successful in obtaining such accounts.
The Company has also expanded its marketing activity to areas beyond its
traditional gas supply centers (Houston and the Gulf Coast) to demand centers,
such as Chicago, New York and California.
The Katy Facility, which commenced operations in February 1994, utilizes a
partially depleted natural gas reservoir with 19 Bcf of working gas capacity and
a pipeline header system, currently connected to eleven pipelines. The Katy
Facility has the capability to deliver up to 400 MMcf per day of natural gas
from the reservoir. In the first two years of the facility's operation, the
Company used a majority of the storage for its own account to take advantage of
the price differential between summer and winter gas. As part of its marketing
plans, the Company intends to increase its long-term firm storage agreements
with local distribution companies from 45% to up to 75% of the available
capacity.
NGLs
The Company's plans for NGL marketing are focused on increasing third-party
sales. The Company is also pursuing industrial end-users of NGLs and recently
entered into a long-term agreement for the sale of approximately two-thirds of
the propane produced at the Granger Plant to a mining company through a
transporter/wholesaler. In addition, the Company plans to spend approximately $5
million in 1996 to upgrade certain processing facilities which will allow for
production of higher-value NGLs. For example, the Company is installing a butane
splitter at the Granger Plant which will permit fractionation of field-grade
butane into normal butane and iso-butane, products that receive a premium over
the field-grade butane.
Electric Power
The Company believes that the anticipated deregulation by states of retail power
marketing will offer the Company significant opportunities to offer both natural
gas and electric power to its existing end-user customer base and to utilize the
Company's demonstrated ability in the natural gas sector to respond quickly to
changing regulatory and market conditions. In 1994, the Company received a
certificate from the FERC to sell electric power at the wholesale level. The
Company intends to dedicate six employees to power marketing by the end of 1996.
The Company is in the process of developing the contractual infrastructure
22
necessary to market power and has already put into place 150 blanket
transmission agreements with carriers and 150 tolling agreements with power
generators to trade natural gas for electric power. There is no assurance that
the retail electric power marketing industry will develop or that the Company
will be successful if the industry develops.
Business Development
The Company's business development activities are oriented towards (i)
identifying and acquiring gas gathering and processing assets and (ii) obtaining
additional gas supplies to maintain or increase throughput levels at the
Company's existing facilities to offset natural production declines.
Historically, the Company has expanded primarily through acquisitions. Since
December 31, 1990, the Company has had a net increase of 13 gas processing
plants and has increased its gas gathering system miles by 188% to 11,079 miles,
resulting in an increase in gas throughput of 370% for the five-year period
ended December 31, 1995. As part of its business plan, the Company will continue
to pursue aggressively gas gathering and processing assets which meet the
Company's target rate of return, with an emphasis on acquisitions that
complement its existing operations or provide growth in marketing.
The Company's business plan assumes that the Company will spend $50 million in
each of 1996, 1997 and 1998 on acquisitions and projects that complement its
current asset base. One of the significant criteria for the Company in making
acquisitions or entering into development projects is that such transactions
have a projected internal rate of return of 20% per year, before income taxes
and financing costs, for a 15-year period, although the Company will also
consider lower return transactions if they provide other opportunities or
benefits. The primary factor affecting internal rates of return is the price of
natural gas, which also generally affects the volumes of natural gas produced by
both the Company and third parties. Other assumptions underlying the Company's
business plan are that for every $1 million in investment, the Company will (i)
spend an additional $100,000 in each succeeding year for new well connects and
related expansion (an aggregate of $5 million per year if the full $50 million
is spent) and (ii) incur an additional $10,000 in general and administrative
costs.
The Company believes that the foregoing criteria and assumptions are reasonable
under current industry and general economic and market conditions. However, the
Company cannot predict the volumes and prices of natural gas and NGLs, and
actual industry and general economic and market conditions could differ, perhaps
significantly, from the conditions that the Company has assumed in projecting
rates of return for transactions. Furthermore, there can be no assurance that
the Company will identify any qualifying transactions or that it will ultimately
be able to acquire assets or enter into such projects.
Operations
The Company continually monitors the economic performance of each of its
operating facilities to ensure that it meets a desired cash flow objective. If
an operating facility is not generating desired cash flows or does not fit in
with the Company's strategic plans, the Company will explore various options,
such as consolidation with other Company-owned facilities, dismantlement, asset
swap or outright sale. In 1995, the Company sold the Waha Header and certain
non-strategic assets acquired in the Oasis acquisition and completed the
consolidation of its Lamont gathering system with the Chaney Dell system. The
Company anticipates completing the salvage of substantially all of the Lamont
processing plant by the end of the first quarter of 1996. In 1994, the Company
sold its Sligo plant, swapped its Pyote treating facilities for gathering assets
in Kansas which were subsequently disposed of during the second quarter of 1995,
consolidated assets in the Powder River Basin and sold its Walnut Bend gathering
system. The Company anticipates that the salvage of the Walnut Bend processing
plant will be substantially completed by the end of the third quarter of 1996.
Commencing in March 1996, the Company and its joint venture partner at the
Lincoln Road gas plant temporarily suspended processing operations at that plant
and began processing the associated gas at the Company's Granger facility. If
volumes increase substantially beyond Granger's capacity, the Lincoln Road plant
might be re-started. The Company anticipates that this consolidation will result
in lower overall plant operating expenses for the combined systems. In January
1996, Koch, which operates the Teddy Roosevelt and Williston assets under a
lease agreement, exercised its option to purchase certain gas gathering assets
located in North Dakota from the Company and Williston. Proceeds from the sale
of the gathering assets totaled $2.4 million of which the Company is entitled to
receive $1.5 million. The closing on the sale is expected to occur on August 1,
1996, at which time the operations of Williston and the Company's Teddy
Roosevelt facility will cease and any remaining assets will be salvaged.
23
Hedging
In order to reduce the impact of commodity price fluctuations on its operating
results, the Company enters into futures contracts and basis positions to hedge
the majority of its natural gas equity production. The following table
summarizes the Company's hedged equity position as of March 1, 1996:
Average Daily Volumes (MMcf/D) Weighted Average Price
--------------------------------------- ---------------------------------------
First Second Third Fourth First Second Third Fourth
Basin Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
- -------------------------- ------- ------- ------- ------- ------- ------- ------- -------
Permian 20,000 15,000 15,000 15,000 $ 1.76 $1.81 $1.81 $1.88
Rocky Mountain 3,407 - - - 1.37 - - -
Gulf Coast 19,121 15,495 14,891 11,630 2.23 1.86 1.81 1.93
Mid-Continent 1,758 5,000 5,000 14,783 $ 1.85 $1.84 $1.85 $1.80
From time to time, the Company also hedges a portion of its share of condensate
and crude oil production, although no such hedges were outstanding at December
31, 1995. The Company will continue hedging such production as deemed
appropriate by management.
24
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements
Western Gas Resources, Inc.'s Consolidated Financial Statements as of December
31, 1995 and 1994 and for each of the three years in the period ended December
31, 1995:
Page
----
Report of Management................................................................ 26
Report of Independent Accountants................................................... 27
Consolidated Balance Sheets......................................................... 28
Consolidated Statements of Cash Flows............................................... 29
Consolidated Statements of Operations............................................... 30
Consolidated Statements of Changes in Stockholders' Equity.......................... 31
Notes to Consolidated Financial Statements.......................................... 32
25
REPORT OF MANAGEMENT
The financial statements and other financial information included in this Annual
Report on Form 10-K are the responsibility of management. The financial
statements have been prepared in conformity with generally accepted accounting
principles appropriate in the circumstances and include amounts that are based
on management's informed judgments and estimates.
Management relies on the Company's system of internal accounting controls to
provide reasonable assurance that assets are safeguarded and that transactions
are properly recorded and executed in accordance with management's
authorization. The concept of reasonable assurance is based on the recognition
that there are inherent limitations in all systems of internal accounting
control and that the cost of such systems should not exceed the benefits to be
derived. The internal accounting controls, including internal audit, in place
during the periods presented are considered adequate to provide such assurance.
The Company's financial statements are audited by Price Waterhouse LLP,
independent accountants. Their report states that they have conducted their
audit in accordance with generally accepted auditing standards. These standards
include an evaluation of the system of internal accounting controls for the
purpose of establishing the scope of audit testing necessary to allow them to
render an independent professional opinion on the fairness of the Company's
financial statements.
Oversight of Management's financial reporting and internal accounting control
responsibilities is exercised by the Board of Directors, through an Audit
Committee that consists solely of outside directors. The Audit Committee meets
periodically with financial management, internal auditors and the independent
accountants to review how each is carrying out its responsibilities and to
discuss matters concerning auditing, internal accounting control and financial
reporting. The independent accountants and the Company's internal audit
department have free access to meet with the Audit Committee without Management
present.
Signature Title
- --------- -----
/s/ BILL M. SANDERSON
- -----------------------------------
Bill M. Sanderson President, Chief Operating Officer and Director
/s/ WILLIAM J. KRYSIAK
- -----------------------------------
William J. Krysiak Vice President - Finance (Principal Financial and
Accounting Officer)
26
REPORT OF INDEPENDENT ACCOUNTANTS
---------------------------------
To the Board of Directors and
Stockholders of Western Gas Resources, Inc.
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of cash flows, of operations, and of changes in
stockholders' equity present fairly, in all material respects, the financial
position of Western Gas Resources, Inc. and its subsidiaries at December 31,
1995 and 1994, and the results of their cash flows and their operations for each
of the three years in the period ended December 31, 1995, in conformity with
generally accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
As discussed in Notes 2 and 3 to the financial statements, the Company changed
its method of accounting for the impairment of long-lived assets in 1995 to
comply with the provisions of Statement of Financial Accounting Standards No.
121.
PRICE WATERHOUSE LLP
Denver, Colorado
February 23, 1996
27
WESTERN GAS RESOURCES, INC.
CONSOLIDATED BALANCE SHEET
(000s)
December 31,
------------------------------
ASSETS 1995 1994
------ ----------- -----------
Current assets:
Cash and cash equivalents.................................................... $ 5,795 $ 8,708
Trade accounts receivable, net............................................... 204,426 134,444
Product inventory............................................................ 28,154 51,139
Parts inventory.............................................................. 2,427 2,291
Other........................................................................ 1,524 1,367
---------- ----------
Total current assets...................................................... 242,326 197,949
---------- ----------
Property and equipment:
Gas gathering, processing, storage and transmission.......................... 882,801 881,569
Oil and gas properties and equipment......................................... 140,691 140,601
Construction in progress..................................................... 26,314 40,076
---------- ----------
1,049,806 1,062,246
Less: Accumulated depreciation, depletion and amortization.................... (200,203) (179,537)
---------- ----------
Total property and equipment, net......................................... 849,603 882,709
---------- ----------
Other assets:
Gas purchase contracts (net of accumulated amortization of $19,273 and
$14,872, respectively).................................................... 54,637 40,958
Other........................................................................ 47,431 45,746
---------- ----------
Total other assets........................................................ 102,068 86,704
---------- ----------
Total assets.................................................................... $1,193,997 $1,167,362
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
Current liabilities:
Accounts payable............................................................. $ 199,513 $ 145,244
Short-term debt.............................................................. 75,000 75,000
Accrued expenses............................................................. 19,204 13,448
Dividends payable............................................................ 3,898 3,895
Income taxes payable......................................................... - 843
---------- ----------
Total current liabilities................................................. 297,615 238,430
Long-term debt.................................................................. 454,500 418,000
Deferred income taxes payable................................................... 69,973 68,727
Other long-term liabilities..................................................... - 5,522
---------- ----------
Total liabilities......................................................... 822,088 730,679
---------- ----------
Commitments and contingent liabilities.......................................... - -
Stockholders' equity:
Preferred Stock; 10,000,000 shares authorized:
7.25% cumulative senior perpetual convertible preferred stock, par value
$.10; none and 400,000 shares issued and outstanding ($40,000
aggregate liquidation preference)...................................... - 40
$2.28 cumulative preferred stock, par value $.10; 1,400,000 shares issued
and outstanding ($35,000 aggregate liquidation preference)............. 140 140
$2.625 cumulative convertible preferred stock, par value $.10; 2,760,000
and issued and outstanding, respectively ($138,000 aggregate
liquidation preference)............................................... 276 276
Common stock, par value $.10; 100,000,000 shares authorized; 25,794,728 and
25,737,317 shares issued, respectively.................................... 2,580 2,574
Treasury stock, at cost; 25,016 shares in treasury........................... (788) (788)
Additional paid-in capital................................................... 301,234 338,926
Retained earnings............................................................ 70,348 97,040
Notes receivable from key employees secured by common stock.................. (1,881) (1,525)
---------- ----------
Total stockholders' equity 371,909 436,683
---------- ----------
Total liabilities and stockholders' equity...................................... $1,193,997 $1,167,362
========== ==========
The accompanying notes are an integral part of the consolidated financial
statements.
28
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(000s)
Year Ended December 31,
--------------------------------------
1995 1994 1993
---------- ----------- ---------
Reconciliation of net income to net cash provided by operating activities
- -------------------------------------------------------------------------
Net income (loss)................................................................ $ (6,108) $ 7,364 $ 38,102
Add income items that do not affect working capital:
Depreciation, depletion and amortization....................................... 65,361 63,586 43,980
Deferred income taxes.......................................................... 1,246 2,246 7,439
Gain on the sale of property and equipment..................................... (939) - -
Loss on the impairment of long-lived assets.................................... 17,642 - -
Other non-cash items........................................................... (1,360) 452 77
---------- --------- ---------
75,842 73,648 89,598
---------- --------- ---------
Adjustments to working capital to arrive at net cash provided by
operating activities:
(Increase) decrease in trade accounts receivable............................... (69,982) 7,892 (38,078)
(Increase) decrease in product inventory....................................... 22,985 (30,289) (2,540)
Increase in parts inventory.................................................... (136) (130) (490)
(Increase) decrease in other current assets.................................... (157) 177 56
Increase in other assets and liabilities, net.................................. (391) (241) (2,845)
Increase (decrease) in accounts payable........................................ 54,269 (15,712) 68,813
Increase (decrease) in accrued expenses........................................ 4,786 (4,322) (7,398)
Increase (decrease) in income taxes payable.................................... (843) 843 -
----------- --------- ---------
Total adjustments............................................................. 10,531 (41,782) 17,518
----------- --------- ---------
Net cash provided by operating activities........................................ 86,373 31,866 107,116
----------- --------- ---------
Cash flows from investing activities:
Payments for business acquisitions............................................. (8,109) (24,685) (302,988)
Payments for additions to property and equipment............................... (48,029) (67,148) (150,216)
Proceeds from the disposition of property and equipment........................ 13,328 10,897 741
Contributions to investments for capital expenditures.......................... (4,237) (1,189) (11,647)
Gas purchase contracts acquired................................................ (18,146) (7,518) (27,477)
--------- --------- ---------
Net cash used in investing activities............................................ (65,193) (89,643) (491,587)
--------- --------- ---------
Cash flows from financing activities:
Net proceeds from issuance of preferred stock.................................. - 132,676 -
Net proceeds from exercise of common stock options............................. 117 413 372
Debt issue costs paid.......................................................... (1,884) (827) (3,611)
Proceeds from short-term borrowings............................................ - 75,000 -
Proceeds from issuance of long-term debt....................................... 92,000 50,000 100,000
Payments on long-term debt..................................................... (25,000) - -
Borrowings under revolving credit facility..................................... 625,400 347,400 594,350
Payments on revolving credit facility.......................................... (655,900) (526,400) (304,350)
Dividends paid to holders of common stock...................................... (5,153) (5,140) (5,124)
Dividends paid to holders of preferred stock................................... (11,643) (11,303) (5,660)
Redemption of 7.25% Cumulative Senior Perpetual Convertible Preferred
Stock......................................................................... (42,030) - -
--------- --------- ---------
Net cash provided by (used in) financing activities............................ (24,093) 61,819 375,977
--------- --------- ---------
Net increase (decrease) in cash.................................................. (2,913) 4,042 (8,494)
Cash and cash equivalents at beginning of period................................. 8,708 4,666 13,160
--------- --------- ---------
Cash and cash equivalents at end of period....................................... $ 5,795 $ 8,708 $ 4,666
========= ========= =========
The accompanying notes are an integral part of the consolidated financial
statements.
29
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
(000s, except share and per share amounts)
Year Ended December 31,
----------------------------------------------
1995 1994 1993
------------ ----------- ------------
Revenues:
Sale of residue gas................................................ $ 876,399 $ 707,869 $ 563,068
Sale of natural gas liquids........................................ 331,760 309,358 333,880
Processing, transportation and storage revenue..................... 41,358 35,057 25,622
Other, net......................................................... 7,467 11,205 9,768
----------- ----------- ------------
Total revenues................................................. 1,256,984 1,063,489 932,338
----------- ----------- ------------
Costs and expenses:
Product purchases.................................................. 1,040,265 853,398 730,676
Plant operating expense............................................ 71,030 68,500 62,387
Oil and gas exploration and production cost........................ 5,117 5,449 3,283
Selling and administrative expense................................. 26,610 29,598 23,925
Depreciation, depletion and amortization........................... 65,361 63,586 43,980
Interest expense................................................... 37,160 31,434 12,456
Restructuring charge............................................... 2,065 - -
Loss on the impairment of long-lived assets........................ 17,642 - -
----------- ----------- ------------
Total costs and expenses....................................... 1,265,250 1,051,965 876,707
----------- ----------- ------------
Income (loss) before taxes............................................ (8,266) 11,524 55,631
Provision (benefit) for income taxes:
Current............................................................ (3,404) 1,913 10,090
Deferred........................................................... 1,246 2,247 7,439
----------- ----------- ------------
Total provision (benefit) for income taxes...................... (2,158) 4,160 17,529
----------- ----------- ------------
Net income (loss)..................................................... (6,108) 7,364 38,102
Preferred stock requirements.......................................... (15,431) (12,212) (6,092)
----------- ----------- ------------
Income (loss) attributable to common stock............................ $ (21,539) $ (4,848) $ 32,010
=========== =========== ============
Earnings (loss) per share of common stock............................. $(.84) $ (.19) $ 1.25
=========== =========== ============
Weighted average shares of common stock outstanding................... 25,753,738 25,695,760 25,608,503
=========== =========== ============
The accompanying notes are an integral part of the consolidated financial
statements.
30
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
(000s, except share amounts)
Shares of
7.25% 7.25%
Cumulative Shares of Cumulative
Senior Shares of $2.625 Senior
Perpetual $2.28 Cumulative Shares Perpetual $2.28
Convertible Cumulative Convertible Shares of Common Convertible Cumulative
Preferred Preferred Preferred of Common Stock Preferred Preferred
Stock Stock Stock Stock in Treasury Stock Stock
---------- --------- ----------- ----------- ----------- ---------- ----------
Balance at December 31,
1992...................... 400,000 1,400,000 - 25,522,575 - $ 40 $ 140
Net income, 1993........... - - - - - - -
Stock options exercised.... - - - 129,147 - - -
Dividends declared on
common stock.............. - - - - - - -
Dividends declared on
7.25% cumulative..........
senior perpetual
convertible preferred
stock..................... - - - - - - -
Dividends declared on
$2.28 cumulative..........
preferred stock........... - - - - - - -
--------- --------- ---------- ----------- --------- ---------- -----------
Balance at December 31,
1993...................... 400,000 1,400,000 - 25,651,722 - 40 140
Net income, 1994........... - - - - - - -
Stock options exercised.... - - - 85,595 - - -
Treasury stock, at cost.... - - - (25,016) 25,016 - -
Proceeds from issuance of
$2.625 cumulative.........
convertible preferred stock - - 2,760,000 - - - -
Dividends declared on
common stock.............. - - - - - - -
Dividends declared on
7.25% cumulative..........
senior perpetual
convertible preferred
stock..................... - - - - - - -
Dividends declared on
$2.28 cumulative..........
preferred stock........... - - - - - - -
Dividends declared on
$2.625 cumulative.........
convertible preferred stock - - - - - - -
--------- --------- ---------- ----------- --------- ---------- -----------
Balance at December 31,
1994...................... 400,000 1,400,000 2,760,000 25,712,301 25,016 40 140
Net loss, 1995............. - - - - - - -
Stock options exercised.... - - - 57,411 - - -
Redemption of 7.25%
cumulative senior......... (400,000) - - - - (40) -
perpetual convertible
preferred stock........... - - - - - - -
Dividends declared on
common stock.............. - - - - - - -
Dividends declared on
7.25% cumulative senior
perpetual convertible
preferred stock........... - - - - - - -
Dividends declared on
$2.28 cumulative..........
preferred stock........... - - - - - - -
Dividends declared on
$2.625 cumulative.........
convertible preferred stock - - - - - - -
--------- --------- ---------- ----------- --------- ---------- -----------
Balance at December 31,
1995...................... - 1,400,000 2,760,000 25,769,712 25,016 $ - $ 140
========= ========= ========== =========== ========= ========== ===========
$2,625
Cumulative Notes Total
Convertible Additional Receivable Stock-
Preferred Common Treasury Paid-In Retained from Key holders'
Stock Stock Stock Capital Earnings Employees Equity
----------- ------ --------- ---------- --------- ---------- ---------
Balance at December 31,
1992...................... - $ 2,552 - $ 204,720 $ 81,047 $ (1,478) $ 287,021
Net income, 1993........... - - - - 38,102 - 38,102
Stock options exercised.... - 13 - 974 - (507) 480
Dividends declared on
common stock.............. - - - - (5,124) - (5,124)
Dividends declared on
7.25% cumulative..........
senior perpetual
convertible preferred
stock..................... - - - - (2,900) - (2,900)
Dividends declared on
$2.28 cumulative..........
preferred stock........... - - - - (3,192) - (3,192)
---------- ---------- ------- ---------- -------- ---------- --------
Balance at December 31,
1993...................... - 2,565 - 205,694 107,933 (1,985) 314,387
Net income, 1994........... - - - - 7,364 - 7,364
Stock options exercised.... - 9 - 831 - (328) 512
Treasury stock, at cost.... - - (788) - - 788 -
Proceeds from issuance of
$2.625 cumulative
convertible preferred stock 276 - - 132,401 - - 132,677
Dividends declared on
common stock.............. - - - - (5,140) - (5,140)
Dividends declared on
7.25% cumulative..........
senior perpetual
convertible preferred
stock..................... - - - - (2,900) - (2,900)
Dividends declared on
$2.28 cumulative..........
preferred stock........... - - - - (3,192) - (3,192)
Dividends declared on
$2.625 cumulative.........
convertible preferred stock - - - - (7,025) - (7,025)
---------- ---------- ------- ---------- -------- ---------- --------
Balance at December 31,
1994...................... 276 2,574 (788) 338,926 97,040 (1,525) (436,683)
Net loss, 1995............. - - - - (6,108) - (6,108)
Stock options exercised.... - 6 - 514 - (356) 164
Redemption of 7.25%
cumulative senior.........
perpetual convertible
preferred stock........... - - - (38,206) (3,784) - (42,030)
Dividends declared on
common stock.............. - - - - (5,153) - (5,153)
Dividends declared on
7.25% cumulative..........
senior perpetual
convertible preferred
stock..................... - - - - (1,208) - (1,208)
Dividends declared on
$2.28 cumulative..........
preferred stock........... - - - - (3,194) - (3,194)
Dividends declared on
$2.625 cumulative.........
convertible preferred stock - - - - (7,245) - (7,245)
---------- ---------- ------- ----------- --------- ---------- ---------
Balance at December 31,
1995...................... $ 276 $ 2,580 $ (788) $ 301,234 $ 70,348 $ (1,881) $371,909
========== ========== ======= ========== ======== ========= ========
The accompanying notes are an integral part of the consolidated financial
statements.
31
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- NATURE OF ORGANIZATION
- ------------------------------
Western Gas Resources, Inc., a Delaware corporation, is an independent gas
gatherer, processor and marketer with operations in major oil and gas-producing
basins in the Rocky Mountain, Gulf Coast and Southwestern regions of the United
States, Western Gas Resources, Inc. owns and operates natural gas gathering,
processing and storage facilities and markets and transports natural gas and
natural gas liquids ("NGLs").
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
had been 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 (the "Principal Stockholders") 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 have been accounted
for at historical cost in a manner similar to poolings of interests.
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 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 1991, the Company issued 4,115,000 shares of common stock at a
public offering price of $18.375 per share.
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.
SIGNIFICANT BUSINESS ACQUISITIONS AND DISPOSITIONS
Northern Acquisition
In July 1995, the Company entered into an agreement to purchase eight West Texas
gathering systems from Transwestern Gathering Company and Enron Permian
Gathering, Inc. In October 1995, the Company acquired and assumed the operations
of the Transwestern Gathering Company assets being sold pursuant to the
agreement for an adjusted purchase price of $4.0 million. Closing on the
remaining assets occurred in December 1995 for a purchase price of $14.7 million
Redman Smackover Joint Venture
Effective January 1, 1995, the Company entered into the Redman Smackover Joint
Venture ("Redman Smackover") agreement with DDD Energy, Inc., a wholly owned
exploration and production subsidiary of Seitel, Inc., Redman Energy
Corporation, and DDD 1995 Oil & Gas Partnership. Redman Smackover acquired
working interests in three producing gas fields in East Texas in the Smackover
formation from Union Oil Company of California for an adjusted purchase price of
$11.0 million. The Company's contribution to the venture was approximately $5.4
million through December 31, 1995. The Company is the managing venturer with a
50% ownership interest.
32
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Oasis
Effective December 1, 1994, the Company acquired the West Texas gathering and
treating assets of Oasis Pipe Line Company ("Oasis") for approximately $26.0
million. The Oasis purchase included 14 gathering systems in the Permian Basin
comprising approximately 600 miles of gathering lines and two treating
facilities. In addition, the Company entered into a long-term agreement with
Oasis for 100 MMcf per day of firm transportation service on its intrastate
pipeline. The Company has installed a 200 MMcf per day pipeline interconnection
between this pipeline and the Katy Facility. Throughout 1995, the Company
disposed of various assets associated with this acquisition for an aggregate of
$8.9 million. The aggregate difference of $677,000 between the respective sales
price and book value of assets sold was accounted for as a purchase price
adjustment.
Mountain Gas
Effective January 1, 1993, the Company acquired the stock of Mountain Gas
Resources, Inc. ("Mountain Gas") from Morgan Stanley Leveraged Equity Fund II,
L.P. for total consideration of approximately $168.2 million, including the
payment of certain transaction costs and the assumption and repayment of $35
million of long-term debt of Mountain Gas. Mountain Gas owns the Red Desert and
Granger facilities. The 22% interest in the Granger facility previously not
owned by Mountain Gas was purchased by the Company in two separate transactions
in November and December 1993 for an aggregate of $27.7 million. At the date of
acquisition, the Red Desert facility consisted of a cryogenic plant and the
Granger plant consisted of a refrigeration unit and a cryogenic unit. In
December 1993, the Company completed construction of an additional cryogenic
processing plant at Granger, at a total additional cost of approximately $4.8
million.
Black Lake
Effective January 1, 1993, the Company purchased the Black Lake gas processing
plant and related reserves ("Black Lake") from Nerco Oil & Gas, Inc. ("Nerco")
for approximately $136.2 million. The acquisition included a 68.9% working
interest in the Black Lake field in Louisiana and a gas processing plant. The
purchase also included 50% of the stock of Black Lake Pipeline Company, which
owns a 240 mile liquids pipeline extending from Cotton Valley, Louisiana to Mont
Belvieu, Texas and transports NGLs for Black Lake and three unaffiliated gas
processing plants. In May 1994, the Company sold its 50% of the stock in Black
Lake Pipeline Company for approximately $5.4 million. The difference of
approximately $2.5 million between the book value and the sales price was
treated as a purchase price adjustment.
Westana Joint Venture
Effective August 1, 1993, the Company formed Westana Gathering Company
("Westana"), a general partnership, with PanEnergy. Westana provides gas
gathering and processing services in the Anadarko Basin in Oklahoma and markets
natural gas and NGLs for producers connected to its system. The Company is the
principal operator with each partner holding a 50% ownership interest.
The Company contributed its Chester gas processing plant and gathering system,
with a net book value of $13.8 million, to Westana. The Company also made
additional contractual partnership contributions of $7.2 million through
December 31, 1995 which are expected to be recouped through preferential
distributions. In addition to the assets contributed by the Company, Westana
operates PanEnergy's 400 mile gathering system and six compressor stations,
assets which will be contributed to Westana by PanEnergy. PanEnergy has
received and accepted abandonment approval by the FERC and is now awaiting
certain clarification of the abandonment approval. Upon clarification from the
Federal Energy Regulatory Commission ("FERC") on the abandonment approval,
PanEnergy will contribute their gathering assets to Westana. The Company
expects the contribution of the PanEnergy assets to occur in 1996.
33
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- ---------------------------------------------------
The significant accounting policies followed by the Company and its wholly owned
subsidiaries are presented herein 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 intercompany transactions
have been eliminated in consolidation. The Company's interest in certain
investments is accounted for by the equity method.
Revenue Recognition
Revenue for sales or services is recognized at the time the natural gas or NGLs
is delivered or at the time the service is performed.
Earnings (Loss) Per Share of Common Stock
Earnings (loss) per share of common stock is computed by dividing net income
(loss) attributable to shares of common stock by the weighted average number of
shares of common stock outstanding. Net income (loss) attributable to shares of
common stock is net income (loss) less preferred stock dividends. The Company
declared preferred stock dividends of $11.6 million, $12.2 million and $6.1
million for the years ended December 31, 1995, 1994 and 1993, respectively. In
addition, net income (loss) for the year ended December 31, 1995 attributable to
common stock was reduced by the $2.0 million redemption premium and certain up-
front costs of $1.8 million paid on the 7.25% Preferred Stock. The computation
of fully diluted earnings per share of common stock for each of the three years
in the period ended December 31, 1995 was not dilutive; therefore, only primary
earnings per share of common stock is presented.
Inventories
Product inventory includes $23.3 million and $47.5 million of residue gas and
$4.8 million and $3.5 million of NGLs at December 31, 1995 and 1994,
respectively.
The cost of residue gas and NGL inventories is determined by the weighted
average cost and last-in, first-out (LIFO) methods, respectively, on a location-
by-location basis. Residue inventory covered by hedging contracts is accounted
for on a specific identification basis.
Property and Equipment
Property and equipment is recorded at the lower of cost or estimated realizable
value, including interest on funds borrowed to finance the construction of new
projects. Interest incurred during the construction period of new projects is
capitalized and amortized over the life of the associated assets. Such
capitalized interest was $1.5 million, $1.5 million and $4.9 million,
respectively, for the years ended December 31, 1995, 1994 and 1993.
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 certain gas purchase contracts is
amortized using the units-of-production 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
34
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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.
Impairment of Long-Lived Assets
As of October 1, 1995, the Company adopted Statement of Financial Accounting
Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed of," which requires that an impairment
loss be recognized when the carrying amount of an asset exceeds the expected
future undiscounted net cash flows. This test is to be performed at the lowest
level at which cash flows can be identified. Historically, the Company had
performed this test for its oil and gas producing properties on a Company-wide
basis. Upon adoption of SFAS No. 121, the Company reviewed its assets at the
plant facilities and oil and gas producing properties levels. In order to
determine whether an impairment existed, the Company compared its net book value
of the asset to the undiscounted expected future cash flows, determined by
applying future prices estimated by management over the shorter of the lives of
the facilities or the reserves supporting the facilities. If impairment existed,
write-downs of assets were based upon expected discounted cash flows using an
interest rate commensurate with the risk associated with the underlying asset.
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 in
accordance with SFAS No. 109, "Accounting for Income Taxes."
Hedging Activities
Gains and losses on hedges of product inventory are included in the carrying
amount of the inventory and are ultimately recognized in residue and NGL sales
when the related inventory is sold. Gains and losses related to qualifying
hedges, as defined by SFAS No. 80, "Accounting for Futures Contracts", of firm
commitments or anticipated transactions are recognized in residue and NGL sales
when the hedged physical transaction occurs. The $1.9 million of losses deferred
in inventory at December 31, 1995, recognized in January 1996, was more than
offset by margins from the Company's related forward fixed price hedges and
physical sales.
Interest Rate Swap Agreements
The Company enters into interest rate swap agreements to manage exposure to
changes in interest rates. The transactions generally involve the exchange of
fixed and floating interest payment obligations without the exchange of the
underlying principal amounts. The net effect of interest rate swap activity is
reflected as an increase or decrease in interest expense. Any gains on
termination of interest rate swap agreements and the effects of foreign currency
positions that were marked to market are included in other income. In addition
to the financial risk that will vary during the life of these swap agreements in
relation to the maturity of the underlying debt and market interest rates, the
Company is subject to credit risk exposure from nonperformance of the
counterparties to the swap agreements.
Concentration of Credit Risk
Financial instruments which potentially subject the Company to concentrations of
credit risk consist principally of trade accounts receivable. 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, 1995, the Company had no significant concentrations of credit risk.
Cash and Cash Equivalents
Cash and cash equivalents includes all cash balances and highly liquid
investments with an original maturity of three months or less.
35
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Supplementary Cash Flow Information
Interest paid was $38.8 million, $32.8 million and $16.4 million, respectively,
for the years ended December 31, 1995, 1994 and 1993.
Income taxes paid were $1.6 million, $1.1 million and $10.2 million,
respectively, for the years ended December 31, 1995, 1994 and 1993.
In February 1994, the President and Chief Operating Officer of the Company,
surrendered 25,016 shares of the Company's common stock, which were valued at
$31.50 per share based upon the February 22, 1994 closing price, as repayment of
a loan and all accrued interest of approximately $788,000.
In 1994, the Company exchanged its Pyote Treating Facility for the Jayhawk
gathering system in a transaction valued at approximately $800,000. In 1993, the
Company exchanged its Fairview Gas Processing Plant for various gas gathering
and processing equipment located in Utah and Kansas in a transaction valued at
approximately $3.7 million.
Use of Estimates and Significant Risks
The preparation of consolidated financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the amounts reported in these financial statements
and accompanying notes. The more significant areas requiring the use of
estimates relate to oil and gas reserves, fair value of financial instruments,
future cash flows associated with assets, and useful lives for depreciation,
depletion and amortization. Actual results could differ from those estimates.
The Company is subject to a number of risks inherent in the industry in which it
operates, primarily fluctuating prices and gas supply. The Company's financial
condition and results of operations will depend significantly upon the prices
received for natural gas and NGLs. These prices are subject to fluctuations in
response to changes in supply, market uncertainty and a variety of additional
factors that are beyond the control of the Company. In addition, the Company
must continually connect new wells to its gathering systems in order to maintain
or increase throughput levels to offset natural declines in dedicated volumes.
The number of new wells drilled will depend upon, among other factors, prices
for gas and oil, the energy policy of the federal government and the
availability of foreign oil and gas, none of which is within the Company's
control.
Reclassification
Certain prior years' amounts in the consolidated financial statements and
related notes have been reclassified to conform to the presentation used in
1995.
Stock Compensation
In October 1995, the Financial Accounting Standards Board issued SFAS No. 123,
"Accounting for Stock-Based Compensation," with an effective date for fiscal
years beginning after December 15, 1995. As permitted under SFAS No. 123, the
Company has elected to continue to measure compensation costs for stock-based
employee compensation plans as prescribed by Accounting Principles Board Opinion
No. 25, "Accounting for Stock Issued to Employees." The Company will comply with
the pro forma disclosure requirements of SFAS No. 123 in 1996 as required under
the pronouncement.
36
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 3 - SPECIAL ITEMS
- ----------------------
In May 1995, the Company implemented a cost reduction program to reduce
operating and selling and administrative expenses. As a result of this program,
a $2.1 million restructuring charge was incurred, primarily related to employee
severance costs. This cost reduction program has not affected adversely the
overall operations of the Company.
In September 1995, the Company sold its 50% interest in the Waha Header, a
pipeline header in West Texas, resulting in an after-tax gain of $596,000.
As a result of the adoption of SFAS No. 121, the Company recognized a non-cash
loss on the impairment of long-lived assets of $15.1 million and $2.5 million
related to its property and equipment and oil and gas properties, respectively.
In December 1993, a fire at the Granger facility's NGL tank farm required the
facility to be shut down for one week. The new cryogenic processing plant as
well as the smaller existing cryogenic unit were also damaged. Construction of a
new tank farm and repairs to the cryogenic units were completed and fully
operational in August 1994. Claims for physical damage to the Company's
facilities totaled approximately $6.7 million. In addition, the Company
recorded, as other revenue, $3.3 million relating to lost income covered under
its business interruption insurance policy for the year ended December 31, 1994.
As of December 31, 1995, the Company had resolved substantially all remaining
issues and collected all remaining insurance proceeds. The total reimbursements
the Company received under its insurance policies were $6.6 million for physical
damage and $3.9 million related to business interruption.
NOTE 4 - RELATED PARTIES
- ------------------------
The Company purchases a significant portion of production from Williston Gas
Company ("Williston"), a joint venture of which the Company owns 50%, Westana
and Redman Smackover for resale to unrelated third parties. In addition, the
Company performs various operational and administrative functions for Williston
and Westana and charges each entity a monthly overhead fee to cover such
services.
The Company records receivable and payable balances at the end of each
accounting period related to the above referenced transactions and to payments
made by the Company on behalf of Williston and Westana that are typically
reimbursed in the next subsequent month.
The following table summarizes account balances reflected in the financial
statements (in 000s):
As of or for the Year Ended December 31,
------------------------------------------
1995 1994 1993
-------- -------- ---------
Purchases:
Williston.......................................... $ 6,533 $ 8,185 $ 8,578
Westana............................................ 14,012 16,290 6,866
Redman Smackover................................... 7,651 - -
Administrative Costs:
Williston.......................................... 60 60 112
Westana............................................ 605 831 264
Accounts Receivable:
Williston.......................................... 968 1,121 1,006
Westana............................................ 544 555 1,111
Redman Smackover................................... 37 - -
Accounts Payable:
Williston.......................................... 943 1,507 2,092
Westana............................................ 1,522 1,526 5,816
Redman Smackover................................... $ 2,514 $ - $ -
37
WESTERN GAS RESOURCES, INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
In July 1990, the Company loaned Bill M. Sanderson, President, Chief Operating
Officer and a Director, approximately $748,000 to purchase 294,524 shares of
common stock in the Company. In February 1994, the loan and all accrued interest
was repaid in full by Mr. Sanderson through surrender of 25,016 shares of the
Company's Common Stock, which were valued at $31.50 per share based upon the
February 22, 1994 closing price.
The Company has entered into agreements committing the Company to loan to
certain key employees an amount sufficient to exercise their options as each
portion of their options vests under the Key Employees' Incentive Stock Option
Plan and the Employee Option Plan (See Note 10). The Company will forgive the
loan and accrued interest if the employee has been continuously employed by the
Company for periods specified under the agreements. As of December 31, 1995 and
1994, loans, including accrued interest, totaling $2.1 million and $1.6 million,
respectively, were outstanding to key 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 1995 and
1994, the Board of Directors approved the forgiveness of loans to key employees
totaling approximately $59,000 and $130,000, respectively, after resignation and
prior to satisfaction of the continuous service requirements of the loan
agreement.
NOTE 5 - RISK MANAGEMENT
- ------------------------
NATURAL GAS AND NGL HEDGES
The Company's policy is to utilize risk management tools primarily to reduce
commodity price risk for its equity production and to lock in profit margins for
its storage and marketing activities. It is the Company's objective to maintain
a balanced portfolio of financial exposure between physical obligations (fixed
price purchase and sales, storage inventories) and related financial instruments
(futures, swaps, and options positions). This effectively allows the Company to
fix its total margin because gains or losses in the physical market are offset
by corresponding losses or gains in the financial instruments market.
Hedging and related activities may expose the Company to the risk of financial
loss in certain circumstances, including instances when (i) production is 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 over-the-
counter ("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.
In 1993, the Board of Directors adopted its Natural Gas Futures Trading
Procedures and created a committee of officers to oversee the Company's risk
management activities. As an additional control, the Company has developed
information systems that allow daily monitoring of its risk management
activities and its exposure related to futures, swaps and options positions
resulting from changes in the market.
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
and the Kansas City Board of Trade and through OTC swaps with creditworthy
counterparties consisting primarily of financial institutions and other natural
gas companies. The Company conducts its standard credit review of OTC
counterparties and has agreements with such parties which contain collateral
requirements. OTC exposure is marked to market daily for the credit review
process. The Company generally uses standardized swap agreements which allow for
offset of positive and negative exposures.
As of December 31, 1995, the Company held a notional quantity of approximately
330 Bcf of natural gas futures, swaps, and options extending from January 1996
to February 1998. This was comprised of approximately 37 Bcf long and 31 Bcf
short of
38
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
exchange-traded futures and 126 long and 136 short Bcf of OTC swaps and options.
As of December 31, 1994, the Company held a notional quantity of approximately
210 Bcf of futures, swaps, and options extending through December 1997. This was
comprised of approximately 34 Bcf long and 58 Bcf short of exchange-traded
futures and 56 long and 62 short Bcf of OTC swaps and options.
The Company enters into speculative futures trades on a very limited basis for
purposes which include testing of hedging techniques. Company procedures contain
strict guidelines for such trading including predetermined stop-loss
requirements and net open positions limits (currently, a total of 100 net
contracts long or short). Speculative futures positions are marked to market at
the end of each accounting period and any gain or loss is recognized in income
for that period. Net gains from such speculative activities for the year ended
December 31, 1995 were not material.
INTEREST RATE SWAPS
In anticipation of issuing the 1995 Senior Notes in the fourth quarter of 1995,
the Company entered into an interest rate lock on a notional amount of $50
million, linked to the ten-year U.S. Treasury Bill rate, with a creditworthy
counterparty to hedge against the risk of rising interest rates while it
completed the 1995 Senior Notes placement. At the time the Company terminated
the rate lock, interest rates had decreased, which resulted in the realization
of a $390,000 loss. The Company considered the loss to be a cost of obtaining
the privately placed debt and is therefore amortizing it over the ten-year term
of the 1995 Senior Notes.
At December 31, 1995 and 1994, the total notional principal amount of
outstanding interest rate swap agreements was $0 and $50 million, respectively.
The following table summarizes the results of the Company's interest rate swap
and foreign currency positions for the years ended December 31, 1995, 1994 and
1993 (000s):
1995 1994 1993
----- ------- --------
Net (increase) decrease to interest expense.......... $ 358 $ (932) $ 1,769
======= ======= =======
Interest rate swap losses capitalized................ $ 390 $ - $ -
======= ======= =======
Gains on swap termination............................ $ - $ - $ 2,590
======= ======= =======
Losses on foreign currency positions................. $ - $ (361) $(1,175)
======= ======= =======
NOTE 6 - FINANCIAL INSTRUMENTS
- ------------------------------
The estimated fair values of the Company's financial instruments have been
determined using appropriate 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, 1995 December 31, 1994
-------------------- -----------------------
Carrying Fair Carrying Fair
Value Value Value Value
-------- -------- -------- ---------
(000s) (000s)
Cash and cash equivalents................. $ 5,795 $ 5,795 $ 8,708 $ 8,708
Trade accounts receivable................. 204,426 204,426 134,444 134,444
Accounts payable.......................... 199,513 199,513 145,244 145,244
Short-term debt........................... 75,000 75,000 75,000 75,000
Long-term debt............................ $ 454,500 $ 453,176 $ 418,000 $ 408,578
39
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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.
Short-term debt
The short-term debt is borrowed on a revolving basis at a variable interest
rate; as a result, the carrying value approximates the fair value of the
outstanding debt.
Long-term debt
A portion of the long-term debt was borrowed under a revolving credit facility
which accrues interest at current rates; as a result, carrying value
approximates fair value. The remaining portion of the Company's long-term debt
is 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.
NOTE 7 - DEBT
- -------------
The following summarizes the Company's consolidated debt at the dates indicated
(000s):
December 31,
-----------------------
1995 1994
-------- --------
Variable rate revolving credit facility... $137,500 $168,000
Master shelf and senior notes............. 292,000 200,000
Bank term loan facility................... 25,000 50,000
-------- --------
Total long-term debt.................... 454,500 418,000
-------- --------
Short-term debt........................... 75,000 75,000
-------- --------
Total debt.............................. $529,500 $493,000
======== ========
Financing Facilities
Revolving Credit Facility. The Company's variable rate Revolving Credit
Facility, as restated on September 2, 1994 and subsequently amended, with a
syndicate of eight banks, provides for a maximum borrowing base of $300 million,
of which $137.5 million was outstanding at December 31, 1995. If the facility
is not renewed, its commitment period will terminate on October 1, 1997. Any
outstanding balance thereunder at such time will convert to a three-year term
loan, which shall be payable in 12 equal quarterly installments, commencing
January 1, 1998. The Revolving Credit Facility bears interest, at the Company's
option, at certain spreads over the Eurodollar rate, at the Federal Funds rate
plus .50%, or at the agent bank's prime rate. The interest rate spreads are
adjusted based on the Company's debt to capitalization ratio. At December 31,
1995, the spread was 1.25% over the Eurodollar rate, resulting in an interest
rate of 7.21%.
The Company pays a commitment fee on the unused commitment ranging from .15% to
.375% based on the debt to capitalization ratio. At December 31, 1995, the
Company's debt to capitalization ratio was .58 to 1 resulting in a commitment
fee rate of .375%.
Term Loan Facility. The Company also has a Term Loan Facility with four banks
for $25 million which bears interest at 9.87%. Payments on the Term Loan
Facility of $12.5 million are due in September 1996 and September 1997,
respectively. The Company intends to finance the $12.5 million payment due in
1996 through amounts available under the Revolving Credit Facility. The
agreements governing the Company's Revolving Credit and Term Loan Facilities
(the "Credit Facilities Agreement") contain certain mandatory prepayment terms.
If funded debt of the Company, which has a final maturity on or before October
1, 2000,
40
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
exceeds four times (4.0 to 1.0) the sum of the Company's last four quarters'
cash flow (as defined in the agreement) less preferred stock dividends projected
to be paid during the next four quarters, the overage must be repaid in no more
than six monthly payments, commencing 90 days from notification. This mandatory
prepayment threshold will be reduced to 3.5 to 1.0 at September 1, 1998. At
December 31, 1995, taking into account all the covenants contained in the Credit
Facilities Agreement, the Company had approximately $50 million of available
borrowing capacity.
The Term Loan and Revolving Credit Facilities are unsecured. Pursuant to the
Credit Facilities Agreement, the Company is required to maintain a current ratio
(as defined therein) of at least 1.0 to 1.0, a minimum tangible net worth equal
to the sum of $345.0 million plus 50% of consolidated net income earned after
June 30, 1995 plus 75% of the net proceeds received after June 30, 1995 from the
sale of equity securities, a debt to capitalization ratio (as defined therein)
of no more than 60% through October 31, 1996 and 55% thereafter, and an EBITDA
to interest ratio of not less than 3.00 to 1.0 through October 31, 1996, 3.25 to
1.0 from November 1, 1996 through October 31, 1997 and 3.75 to 1.0 thereafter.
The Company is prohibited from declaring or paying dividends on or after
December 31, 1995 that in the aggregate exceed the sum of $10 million plus 50%
of consolidated net income earned after December 31, 1995 plus 50% of the
cumulative net proceeds received by the Company after December 31, 1995 from the
sale of any equity securities. The dividends declared in the fourth fiscal
quarter of 1995, payable in 1996, are excluded from this calculation. At
December 31, 1995, $10 million was available under this limitation, which is
sufficient to pay required preferred stock dividends in 1996. The Company
generally utilizes excess daily funds to reduce any outstanding revolving credit
balances and associated interest expense and it intends to continue such
practice. The $5.8 million cash balance at December 31, 1995 is an overnight
investment necessitated by the timing of cash receipts.
Master Shelf Agreement. In December 1991, the Company entered into a Master
Shelf Agreement (the "Master Shelf") with The Prudential Insurance Company of
America ("Prudential") pursuant to which Prudential agreed to quote, from time-
to-time, an interest rate at which Prudential or its nominee would be willing to
purchase up to $100 million of the Company's senior promissory notes (the
"Master Notes"). Any such Master Notes will mature in no more than 12 years,
with an average life not in excess of 10 years, and are unsecured. The Master
Shelf contains certain financial covenants which substantially conform with
those contained in the Revolving Credit Facility, as restated and amended. In
July 1993 and July 1995, Prudential and the Company amended the Master Shelf to
provide for additional borrowing capacity (for a total borrowing capacity of
$200 million) and to extend the term of the Master Shelf to October 31, 1995.
The Master Shelf Agreement, as restated and amended, is fully utilized, as
indicated in the following table (000s):
Interest Final
Issue Date Amount Rate Maturity Principal Payments Due
- --------------------- -------- ----- ------------------ --------------------------------------------
October 27, 1992 $25,000 7.51% October 27, 2000 $8,333 each on October 27, 1998 through 2000
October 27, 1992 25,000 7.99% October 27, 2003 $8,333 each on October 27, 2001 through 2003
September 22, 1993 25,000 6.77% September 22, 2003 single payment at maturity
December 27, 1993 25,000 7.23% December 27, 2003 single payment at maturity
October 27, 1994 25,000 9.05% October 27, 2001 single payment at maturity
October 27, 1994 25,000 9.24% October 27, 2004 single payment at maturity
July 28, 1995 50,000 7.61% July 28, 2007 $10,000 each on July 28, 2003 through 2007
-------
$200,000
========
1993 Senior Notes. On April 28, 1993 the Company sold $50 million of 7.65%
Senior Notes due 2003 to a group of insurance companies. Annual principal
payments of $7.1 million on the 1993 Senior Notes are due on April 30 of each
year from 1997 through 2002, with any remaining principal and interest
outstanding due on April 30, 2003. The 1993 Senior Notes contain certain
financial covenants that substantially conform with those contained in the
Master Shelf Agreement, as restated and amended.
1995 Senior Notes. The Company sold $42 million of 1995 Senior Notes to a group
of insurance companies in the fourth quarter of 1995, with an interest rate of
8.16% per annum and principal due in a single payment in December 2005. The 1995
Senior Notes contain certain financial covenants that conform with those
contained in the Master Shelf Agreement, as restated and amended. The Company
used the net proceeds from the sale to reduce borrowings under the Revolving
Credit Facility.
41
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Receivables Facility. In April 1995, the Company entered into an agreement with
Receivables Capital Corporation ("RCC"), as purchaser, and Bank of America
National Trust and Savings Association ("BA"), as agent, pursuant to which the
Company will sell to RCC at face value on a revolving basis an undivided
interest in certain of the Company's trade receivables. As part of the sale, the
Company granted to RCC a security interest in such receivables. The Company may
sell up to $75 million of trade receivables under the Receivables Facility, at a
rate equal to RCC's commercial paper rate plus .375%, of which $75 million was
funded at a rate of 6.3% as of December 31, 1995. The Receivables Facility has a
364-day term and contains financial covenants similar to those in the Credit
Facilities Agreement, as restated and amended, along with certain covenants
regarding the quality of the trade receivables pool.
On September 2, 1994, in anticipation of entering into the Receivables Facility,
BA entered in a Master Note Agreement (the "Short-Term Note") with the Company
and advanced the Company $75 million at the Eurodollar rate plus .50%, which
resulted in an interest rate of 6.56% per annum at June 30, 1995. The Company
used the $75 million drawn on the Receivables Facility to repay the Short-Term
Note, which was then canceled.
COVENANT COMPLIANCE. At December 31, 1995, the Company was in compliance with
all covenants in its loan agreements.
Approximate future maturities of long-term debt at the date indicated are as
follows at December 31, 1995 (in 000s):
1996........................................ $ 12,500
1997........................................ 54,019
1998........................................ 49,852
1999........................................ 49,852
2000........................................ 49,849
Thereafter.................................. 238,428
--------
$454,500
========
NOTE 8 - INCOME TAXES
- ---------------------
The provision (benefit) for income taxes for the years ended December 31, 1995,
1994 and 1993 is comprised of (000s):
1995 1994 1993
-------- ------ -------
Current:
Federal............................................... $(3,404) $1,913 $10,090
State................................................. - - -
------- ------ -------
Total Current......................................... (3,404) 1,913 10,090
------- ------ -------
Deferred:
Federal............................................... 1,192 2,113 6,411
State................................................. 54 134 1,028
------- ------ -------
Total Deferred........................................ 1,246 2,247 7,439
------- ------ -------
Total tax provision.................................. $(2,158) $4,160 $17,529
======= ====== =======
42
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Temporary differences and carryforwards which give rise to the deferred tax
(assets) liabilities at December 31, 1995 and 1994 are as follows (000s):
1995 1994
-------- --------
Property and equipment.................................................. $113,796 $ 91,633
Differences between the book and tax basis of acquired assets........... 21,235 22,750
-------- --------
Total deferred tax liabilities....................................... 135,031 114,383
-------- --------
Alternative Minimum Tax ("AMT") credit carryforward..................... (25,450) (25,059)
Net Operating Loss ("NOL") carryforwards................................ (39,608) (20,597)
-------- --------
Total deferred tax assets............................................ (65,058) (45,656)
-------- --------
Net deferred income taxes............................................ $ 69,973 $ 68,727
======== ========
The differences between the provision for income taxes at the statutory rate and
the actual provision for income taxes for the years ended December 31, 1995,
1994 and 1993 are summarized as follows (000s):
1995 % 1994 % 1993 %
------- ------ ------- ----- -------- -----
Income tax (benefit) at statutory rate................. $ (2,893) (35.0) $ 4,033 35.0 $ 19,471 35.0
State income taxes, net of federal
benefit............................................. (99) (1.2) 158 1.4 656 1.2
Permanent differences on asset write-downs............. 1,173 14.2 - - - -
Increase in deferred income taxes to reflect the
change in the federal tax rate...................... - - - - 2,100 3.8
Reduction of deferred income taxes to reflect NOL and
AMT benefit carryforwards........................... - - - - (3,779) (6.8)
Adjustment to prior year income taxes.................. (300) (3.6) - - - -
Other.................................................. (39) (.5) (31) (0.3) (919) (1.7)
------- ----- ------ ---- ------- ----
Total.................................................. $ (2,158) (26.1) $ 4,160 36.1 $ 17,529 31.5
======= ===== ====== ==== ======= ====
At December 31, 1995, the Company had NOL and AMT credit carryforwards for
Federal and State income tax purposes of approximately $108.6 million and $25.5
million, respectively. These carryforward expire as follows (000s):
Expiration Dates NOL AMT
----------------------------- -------- --------
2003......................... $ 170 $ -
2004......................... 412 -
2005......................... 943 -
2006......................... 478 -
2007......................... 1,080 -
2008......................... 6,561 -
2009......................... 51,115 -
2010......................... 47,835 -
No expiration................ - 25,450
-------- --------
Total........................ $108,594 $25,450
======== ========
43
WESTERN GAS RESOURCES, INC.
NOTES TO COSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The Company believes that the carryforwards will be utilized prior to their
expiration because they are substantially offset by existing taxable temporary
differences reversing within the carryforward period or are expected to be
realized by achieving future profitable operations based on the Company's
dedicated and owned reserves, past earnings history, projections of future
earnings and current assets.
NOTE 9 - COMMITMENTS AND CONTINGENT LIABILITIES
- -----------------------------------------------
Katy Condemnation
Commencing in March 1993 and continuing through July 1993, Western Gas Resources
Storage, Inc. ("Storage"), a wholly owned subsidiary of the Company, filed a
total of 165 condemnation actions in the County Court at Law No. 1 and No. 2 of
Fort Bend County, Texas, to obtain certain storage rights and rights-of-way
relating to its Katy Gas Storage Facility and the related underground reservoir
("Katy"). The County Court appointed panels of Special Commissioners which
awarded compensation to the owners whose rights were condemned. Condemnation
awards are a capital cost of the Katy project.
A majority of the land and mineral owners involved in the condemnation
proceedings appealed to County Court, seeking a declaration that Storage did not
possess the right to condemn or, in the alternative, that they should be awarded
more compensation than previously awarded by the Special Commissioners. In all
of those appeals, the right to condemn issue has been resolved in favor of
Storage, although factual issues in individual cases remain open as to whether
that right was exercised properly.
Trials in four of the appeals to County Court have now been concluded. The
first trial involved a parcel adjacent to the 82 acre site where the compression
facilities are located, the second trial involved a parcel within 1,000 feet of
the 82 acre site, and the third and fourth trials involved parcels further than
one mile from the 82 acre site. The jury verdicts compared with the awards of
the Special Commissioners were, respectively, as follows: $214,000 versus
$2,000; $38,000 versus $600; $553 versus $553; and $1,000 versus $500. The
Company believes that several reversible errors were committed in the first two
trials and appeals of those cases are now pending in the Texas Court of Appeals.
Internal Revenue Service
The Internal Revenue Service ("IRS") has completed its examination of the
Company's returns for the years 1990 and 1991 and has proposed adjustments to
taxable income reflected in such returns which would shift the recognition of
certain items of income and expense from one year to another ("Timing
Adjustments"). To the extent taxable income in a prior year is increased by
proposed Timing Adjustments, taxable income may be reduced by a corresponding
amount in other years. However, the Company would incur an interest charge as a
result of such adjustment. The Company currently is protesting certain of these
proposed adjustments through the IRS appeals process. In the opinion of
management, adequate provision has been made for the additional income taxes and
interest which may result from the proposed adjustments. However, it is
reasonably possible that the ultimate resolution could result in an amount which
differs materially from amounts provided.
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 (net of insurance) that may result from these
claims, as well as the specific claim discussed above, will not, individually or
in the aggregate, have a material adverse effect on the Company's financial
position or results of operations.
44
WESTERN GAS RESOURCES, INC.
NOTES TO COSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 makes annual
contributions to the plan as determined by the Board of Directors and provides
for a match of 1% up to 4% of employee contributions. Contributions are made to
common/collective trusts for which Fidelity Management Trust Company acts as
trustee. The discretionary contributions were $1.3 million, $1.3 million and
$2.2 million, for the years ended December 31, 1995, 1994 and 1993,
respectively. The matching contributions were $227,000, $264,000 and $272,000
for the years ended December 31, 1995, 1994 and 1993, respectively.
$5.40 Stock Option Plan
In April 1987, the Partnership adopted an employee option plan ("$5.40 Plan")
that authorizes granting options to employees to purchase 430,000 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. In February 1994, the Board of
Directors retroactively approved, adopted and ratified approximately 53,000
options granted to employees in excess of the 430,000 options originally
authorized. No additional options may be granted under this plan. Options may be
exercised only at the rate of 20% of the shares of common stock subject to such
option for each year of continuous service by the optionee commencing from the
later of July 2, 1987 or the optionee's employment commencement date. The
Company has entered into agreements committing the Company to loan to certain
key 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. The Company will forgive any associated loan and
accrued interest on July 2, 1997, if the employee is then employed by the
Company. As of December 31, 1995 and 1994, loans and accrued interest related to
100,374 and 96,963 shares of common stock, respectively, totaling $637,000 and
$545,000, were outstanding under these terms.
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 latter of each subsequent January 1 through 1995 or on each
subsequent date of grant anniversary, subject to the same condition. The Company
has entered into agreements committing the Company to loan certain key employees
an amount sufficient to exercise their options as each portion of their options
vests. The Company will forgive the associated loan and accrued interest if the
employee has been continuously employed by the Company for four years after the
date of each loan increment. As of December 31, 1995 and 1994, loans and accrued
interest related to 125,000 and 93,750 shares of common stock, respectively,
totaling $1.5 million and $1.1 million, were outstanding under these terms.
1993 Stock Option Plan
The 1993 Stock Option Plan (the "1993 Plan") became effective on May 24, 1993
after approval by the Company's stockholders. The 1993 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 the
1993 Plan. The 1993 Plan will terminate on the earlier of March 28, 2003 or the
date on which all options granted under the 1993 Plan have been exercised in
full.
45
WESTERN GAS RESOURCES, INC.
NOTES TO COSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 shall be released and may be subject to reissuance pursuant to a new
option. The Board of Directors has the right to, among other things, fix the
price, terms and conditions for the grant or exercise of any option. The
purchase price of the stock under each option shall be the fair market value of
the stock at the time such option is granted. Options granted will vest 20% each
year on the anniversary of the date of grant commencing with the first
anniversary. The employee must exercise the option within five years of the date
each portion vests. At December 31, 1995 approximately 170,344 options were
vested. No options have been exercised under the 1993 plan.
The following table summarizes the stock option activity under the Company's
employee benefit plans:
Per Share Number of Shares
----------------------------------------------------------
Price Key Employee Director's
Range $5.40 Plan Plan Plan 1993 Plan
---------------- ------------- ------------ ----------- -----------
Balance 1/1/93.............. 214,456 112,500 15,000 -
Granted................. $26.50 - $35.50 - 75,000 - 385,394
Exercised............... 5.40 - 10.71 (90,147) (37,500) (1,500) -
Forfeited or canceled... 5.40 - 35.00 (3,924) - - (16,760)
------------ ---------- ----------- -----------
Balance 12/31/93............ 120,385 150,000 13,500 368,634
Granted................. 18.63 - 32.50 - - 5,000 321,464
Exercised............... 5.40 - 10.71 (44,345) (37,500) (3,750) -
Forfeited or canceled... 5.40 - 35.00 (692) (6,250) (1,250) (52,512)
------------ ---------- ----------- -----------
Balance 12/31/94............ 75,348 106,250 13,500 637,586
Granted................. 16.13 - 23.50 - - - 137,567
Exercised............... 5.40 - 15.00 (26,161) (31,250) -
Forfeited or canceled... $5.40 - $35.00 (1,616) - - (87,092)
------------ ---------- ----------- -----------
Balance 12/31/95............ 47,571 75,000 13,500 688,061
============ ========== =========== ===========
46
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 11 - SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
- ----------------------------------------------------------------------
(UNAUDITED):
- -----------
Costs
The following tables set forth capitalized costs at December 31, 1995, 1994 and
1993 and costs incurred for oil and gas producing activities for the years ended
December 31, 1995, 1994 and 1993 (000s):
1995 1994 1993
--------- --------- ---------
Capitalized costs:
Proved properties.............................................. $136,499 $136,861 $130,783
Unproved properties............................................ 6,279 7,448 3,855
-------- -------- --------
Total............................................................ 142,778 144,309 134,638
Less accumulated depletion..................................... (46,792) (35,346) (17,877)
-------- -------- --------
Net capitalized costs............................................ $ 95,986 $108,963 $116,761
======== ======== ========
The Company's share of Redman Smackover's net capitalized costs.. $ 5,216 $ - $ -
======== ======== ========
Costs incurred:
Acquisition of properties
Proved......................................................... $ 1,591 $ 2,523 $ 95,518
Unproved....................................................... 128 1,617 2,428
Development costs................................................ 3,035 3,555 1,106
Exploration costs................................................ 1,102 2,465 320
-------- -------- --------
Total costs incurred............................................. $ 5,856 $ 10,160 $ 99,372
======== ======== ========
The Company's share of Redman Smackover's costs incurred......... $ 5,540 $ - $ -
======== ======== ========
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, 1995,
1994 and 1993 are as follows (000s):
1995 1994 1993
--------- --------- ---------
Revenues from sale of oil and gas:
Sales............................................... $ 2,490 $ 3,402 $ 4,112
Transfers........................................... 29,739 37,335 27,567
-------- -------- --------
Total............................................ 32,229 40,737 31,679
Production costs...................................... (4,160) (4,960) (2,963)
Exploration costs..................................... (956) (489) (320)
Depreciation, depletion and amortization.............. (15,081) (17,469) (10,857)
Income tax expense.................................... (4,429) (6,030) (6,321)
-------- -------- --------
Results of operations................................. $ 7,603 $ 11,789 $ 11,218
======== ======== ========
The Company's share of Redman Smackover's operations.. $ 324 $ - $ -
======== ======== ========
47
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Reserve Quantity Information
Reserve estimates are subject to numerous uncertainties inherent in the
estimation of quantities of proved reserves and in the projection of future
rates of production and the timing of development expenditures. The accuracy of
such estimates is a function of the quality of available data and of engineering
and geological interpretation and judgement. 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 prices and operating costs. Reserve estimates, by
their nature, are generally less precise than other financial statement
disclosures.
The following table sets forth information for the years ended December 31,
1995, 1994 and 1993 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, 1992........................................................ 39,475 381
Revisions of previous estimates.......................................... 11,084 (42)
Purchases of reserves in place*.......................................... 100,886 261
Production............................................................... (15,854) (107)
-------- -------
December 31, 1993........................................................ 135,591 493
Revisions of previous estimates.......................................... 19,562 35
Purchases of reserves in place........................................... 977 121
Production............................................................... (21,589) (171)
-------- -------
December 31, 1994........................................................ 134,541 478
Revisions of previous estimates.......................................... (8,846) 437
Production............................................................... (16,875) (200)
-------- -------
December 31, 1995........................................................ 108,820 715
======== =======
The Company's share of Redman Smackover's proved reserves - December 31, 1995 12,647 -
======== =======
(*) Primarily represents acquisition of Black Lake oil and gas properties
effective January 1, 1993 from Nerco (See Note 1).
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. 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 proven reserves to the year-end quantities of those
reserves. Future price changes are considered only to the extent provided by
contractual arrangements, including futures contracts, in existence at year-end.
The assumptions used to compute estimated future net revenues do not necessarily
reflect the Company's expectations of actual revenues or costs, nor their
present worth. In addition, variations from the expected production rate also
could result directly or indirectly from factors outside of the Company's
control, such as unintentional delays in development, changes in prices or
48
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 pretax net cash flows relating to the Company's proved oil and gas
reserves. Permanent differences in oil and gas related tax credits and
allowances are recognized.
An annual discount rate of 10% was used to reflect the timing of the future net
cash flows relating to proved oil and gas reserves.
Information with respect to the Company's estimated discounted future cash flows
from its oil and gas properties for the years ended December 31, 1995, 1994 and
1993 is as follows (000s):
1995 1994 1993
--------- --------- ---------
Future cash inflows........................................................ $230,986 $239,188 $261,497
Future production costs.................................................... (52,442) (50,214) (36,978)
Future development costs................................................... (3,564) (9,230) (12,623)
Future income tax expense.................................................. (32,125) (26,811) (35,856)
-------- -------- --------
Future net cash flows...................................................... 142,855 152,933 176,040
10% annual discount for estimated timing of cash flows..................... (61,093) (57,202) (51,915)
-------- -------- --------
Standardized measure of discounted future net cash flows relating to
proved oil and gas reserves........................................... $ 81,762 $ 95,731 $124,125
======== ======== ========
The Company's share of Redman Smackover's standardized measure of
discounted future net cash flows relating to proved oil and gas reserves $ 4,665 $ - $ -
======== ======== ========
Principal changes in the Company's estimated discounted future net cash flows
for the years ended December 31, 1995, 1994 and 1993 are as follows (000s):
1995 1994 1993
--------- --------- ---------
January 1................................................................. $ 95,731 $124,125 $ 35,922
Sales and transfers of oil and gas produced, net of production costs..... (28,069) (35,777) (28,716)
Net changes in prices and production costs related to future production.. 14,499 (33,909) 2,318
Development costs incurred during the period............................. 3,035 3,555 1,106
Changes in estimated future development costs............................ 2,631 (162) (12,623)
Revisions of previous quantity estimates................................. (12,147) 14,830 17,819
Purchases of reserves in place........................................... - 3,882 118,894
Accretion of discount.................................................... 9,573 12,413 3,592
Net change in income taxes............................................... (5,314) 9,045 (13,470)
Other.................................................................... 1,823 (2,271) (717)
-------- -------- --------
December 31............................................................... $ 81,762 $ 95,731 $124,125
======== ======== ========
49
NOTE 12 - QUARTERLY RESULTS OF OPERATIONS (UNAUDITED):
- ------------------------------------------------------
The following summarizes certain quarterly results of operations (000s except
per share amounts):
Earnings
(Loss) Per
Net Share of
Operating Gross Income Common
Revenues Profit(a) (Loss) Stock
-------- --------- --------- -----
1995 quarter ended:
March 31................................. $ 303,701 $18,444 $ 1,941 $(.05)
June 30.................................. 304,408 17,671 (403) (.28)
September 30............................. 286,705 16,518 462 (.08)
December 31.............................. 362,170 22,578 (8,108) (b) (.43)
---------- ------- ------- -----
$1,256,984 $75,211 $(6,108) (b) $(.84)
========== ======= ======= =====
1994 quarter ended:
March 31................................. $ 275,704 $16,562 $ 1,011 $(.05)
June 30.................................. 244,470 14,851 181 (.12)
September 30............................. 259,669 19,585 2,706 (.02)
December 31.............................. 283,646 21,558 3,466 -
---------- ------- ------- ----
$1,063,489 $72,556 $ 7,364 $(.19)
========== ======= ======= =====
(a) Excludes selling and administrative, interest, restructuring and income tax
expenses.
(b) Includes a non-cash expense resulting from the adoption of SFAS No. 121 of
$17.6 million.
As a result of the reclassification of labor overhead from selling and
administrative expense to plant operating expense in accordance with the
percentage established by the Council of Petroleum Accountants Society
guidelines, gross profit varies from the amounts reported on prior Forms 10-Q
and Form 10-K for years ended December 31, 1994.
50
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Pursuant to instruction G(3) to Form 10-K, Items 10, 11, 12 and 13 are omitted
because the Company will file a definitive proxy statement (the "Proxy
Statement") pursuant to Regulation 14A under the Securities Exchange Act of 1934
not later than 120 days after the close of the fiscal year. The information
required by such Items will be included in the definitive proxy statement to be
so filed for the Company's annual meeting of stockholders scheduled for May 22,
1996 and is hereby incorporated by reference.
51
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 the listing on page 25 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 Bylaws of Western Gas Resources, Inc. (Filed as exhibit 3.3 to Western
Gas Resources, Inc.'s Registration Statement on Form S-1, Registration
No. 33-31604 and incorporated herein by reference).
3.4 Assistant Secretary's Certificate regarding amendment to bylaws of
Western Gas Resources, Inc. (Filed as exhibit 3.4 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).
3.5 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).
3.6 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).
3.7 Amendments of the By-Laws of Western Gas Resources, Inc. as adopted by
the Board of Directors on December 13, 1993 (Filed as exhibit 3.7 to
Western Gas Resources, Inc.'s Form 10-K for the year ended December
31, 1993 and incorporated herein by reference).
3.8 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 Subscription Agreements between the respective Founders and Western
Gas Resources, Inc. regarding such Founders' initial subscription for
shares of common stock (Filed as exhibit 10.31 to Western Gas
Resources, Inc.'s Registration Statement on Form S-4, Registration No.
33-39588 dated March 27, 1991 and incorporated herein by reference).
4.2 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).
10.1 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).
52
10.2 Employees Common Units Option Plan of Western Gas Processors, Ltd.
(Filed as exhibit 10.9 to Western Gas Resources, Inc.'s Registration
Statement on Form S-4, Registration No. 33-39588 dated March 27, 1991
and incorporated herein by reference).
10.3 Amendment to Employees Common Units Option Plan of Western Gas
Processors, Ltd. (Filed as exhibit 10.10 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 Western Gas Resources, Inc. Non-Employee Director Stock Option Plan
(Filed as exhibit 10.12 Western Gas Resources, Inc.'s Registration
Statement on Form S-4, Registration No. 33-39588 dated March 27, 1991
and incorporated herein by reference).
10.5 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).
10.6 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).
10.7 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).
10.8 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).
10.9 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).
10.10 Agreement and Plan of Restructuring among the Company, the
Partnership and the Founders (Filed as exhibit 10.10 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).
10.11 Stock Purchase Agreement dated October 23, 1991 between the Company
and The 1818 Fund, L.P. (Filed as exhibit 10.19 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).
10.12 Registration Rights Agreement dated October 23, 1991 between the
Company and The 1818 Fund, L.P. (Filed as exhibit 10.20 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).
10.13 Letter Agreement dated June 10, 1992 amending the Stock Purchase
Agreement dated October 23, 1991 between the Company and the 1818
Fund, L.P. (Filed as exhibit 10.36 to Western Gas Resources, Inc.'s
Form 10-Q for the quarter ended June 30, 1992 and incorporated herein
by reference).
10.14 $100,000,000 Senior Notes Master Shelf Agreement dated as of December
19, 1991 by and between the Company and the Prudential Insurance
Company of America (Filed as exhibit 10.23 to Western Gas Resources,
Inc.'s Registration Statement on Form S-1, Registration No. 33-53786
dated November 12, 1992 and incorporated herein by reference).
10.15 Letter Amendment No. 1 dated October 22, 1992 to $100,000,000 Senior
Notes Master Shelf Agreement (Filed as exhibit 10.40 to Western Gas
Resources, Inc's Form 10-K for the year ended December 31, 1992 and
incorporated herein by reference).
53
10.16 Stock Purchase Agreement (without exhibits) dated March 30, 1993 by
and between the Company and The Morgan Stanley Leveraged Equity Fund
II, L.P. (Filed as exhibit 10.45 to Western Gas Resources Inc.'s Form
10-Q for the six months ended June 30, 1993 and incorporated herein
by reference).
10.17 Amendment No. 1 (without exhibits) to Stock Purchase Agreement dated
as of March 30, 1993 by and between the Company and The Morgan
Stanley Leveraged Equity Fund II, L.P. (Filed as exhibit 10.46 to
Western Gas Resources Inc.'s Form 10-Q for the six months ended June
30, 1993 and incorporated herein by reference).
10.18 $150,000,000 Amended and Restated Master Shelf Agreement (without
exhibits) effective as of July 22, 1993 by and between the Company
and Prudential Insurance Company of America (Filed as exhibit 10.47
to Western Gas Resources Inc.'s Form 10-Q for the six months ended
June 30, 1993 and incorporated herein by reference).
10.19 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).
10.20 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).
10.21 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).
10.22 Operating and Maintenance Agreement (without exhibits) dated August
10, 1993 by and between Western Gas Resources - Oklahoma, Inc. (a
subsidiary of the Company) and Panhandle Gathering Company (Filed as
exhibit 10.52 to Western Gas Resources Inc.'s Form 10-Q for the six
months ended June 30, 1993 and incorporated herein by reference).
10.23 Amendment to Operating and Maintenance 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 10.53 to Western Gas Resources Inc.'s Form 10-Q for the six
months ended June 30, 1993 and incorporated herein by reference).
10.24 Pipeline Operating Agreement (without exhibits) dated August 10, 1993
by and between Westana Gathering Company and Panhandle Eastern Pipe
Line Company (Filed as exhibit 10.56 to Western Gas Resources Inc.'s
Form 10-Q for the six months ended June 30, 1993 and incorporated
herein by reference).
10.25 Letter Amendment No. 1 to the Amended and Restated Master Shelf
Agreement effective as of June 30, 1993 by and between the Company
and Prudential Insurance Company of America (Filed as exhibit 10.59
to Western Gas Resources Inc.'s Form 10-Q for the nine months ended
September 30, 1993 and incorporated herein by reference).
10.26 Asset Purchase Agreement (without exhibits) dated July 18, 1993 by
and between the Company and Nerco Oil & Gas, Inc. (Filed as exhibit
10.60 to Western Gas Resources Inc.'s Form 10-Q for the nine months
ended September 30, 1993 and incorporated herein by reference).
10.27 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).
10.28 First Amendment to Stock Purchase Agreement, amending the Stock
Purchase Agreement dated October 23, 1991 between Western Gas
Resources, Inc. and the 1818 Fund, L.P. (Filed as exhibit 10.62 to
Western Gas Resources, Inc.'s Form 10-K for the year ended December
31, 1993 and incorporated herein by reference).
54
10.29 First Restated Loan Agreement (Revolver) (without exhibits) as of
September 2, 1994 among Western Gas Resources, Inc. and NationsBank
of Texas, N.A. as Agent and Certain Banks as Lenders. (Filed as
exhibit 10.65 to Western Gas Resources, Inc.'s Form 10-Q for the nine
months ended September 30, 1994 and incorporated herein by
reference).
10.30 Second Amendment to Third Restated Loan Agreement (Term) as of
September 2, 1994 among Western Gas Resources, Inc. and NationsBank
of Texas, N.A. as Agent and Certain Banks as Lenders. (Filed as
exhibit 10.66 to Western Gas Resources, Inc.'s Form 10-Q for the nine
months ended September 30, 1994 and incorporated herein by
reference).
10.31 Letter Amendment No. 2 to the Amended and Restated Master Shelf
Agreement effective as of August 31, 1994 by and between Western Gas
Resources, Inc. and Prudential Insurance Company of America. (Filed
as exhibit 10.67 to Western Gas Resources, Inc.'s Form 10-Q for the
nine months ended September 30, 1994 and incorporated herein by
reference).
10.32 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).
10.33 Master Note dated September 2, 1994 between Western Gas Resources,
Inc. and Bank of America National Trust and Savings Association.
(Filed as exhibit 10.69 to Western Gas Resources, Inc.'s Form 10-Q
for the nine months ended September 30, 1994 and incorporated herein
by reference).
10.34 First Amendment to First Restated Loan Agreement (Revolver) as of
December 2, 1994 by and among Western Gas Resources, Inc. and
NationsBank of Texas, N.A. as Agent and Certain Banks as Lenders.
(Filed as exhibit 10.34 to Western Gas Resources, Inc.'s Form 10-K
for the year ended December 31, 1994 and incorporated herein
by reference).
10.35 Third Amendment to Third Restated Loan Agreement (Term) as of
December 2, 1994 by and among Western Gas Resources, Inc. and
NationsBank of Texas, N.A. as Agent and Certain Banks as Lenders.
(Filed as exhibit 10.35 to Western Gas Resources, Inc.'s Form 10-K
for the year ended December 31, 1994 and incorporated herein by
reference).
10.36 Second Amendment to First Restated Loan Agreement (Revolver) as of
February 23, 1995 among Western Gas Resources, Inc. and Nations Bank
of Texas, N.A. as Agent and Certain Banks as Lenders. (Filed as
exhibit 10.36 to Western Gas Resources, Inc.'s Form 10-Q for the
three months ended March 31, 1995 and incorporated herein by
reference).
10.37 Fourth Amendment to Third Restated Loan Agreement (Term) as of
February 23, 1995 among Western Gas Resources, Inc. and NationsBank
of Texas, N.A. as Agent and Certain Banks as Lenders. (Filed as
exhibit 10.37 to Western Gas Resources, Inc.'s Form 10-Q for the
three months ended March 31, 1995 and incorporated herein by
reference).
10.38 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).
10.39 Letter Amendment No. 3 To the Amended and Restated Master Shelf
Agreement effective as of April 1, 1995 by and between Western Gas
Resources, Inc. and Prudential Insurance Company of America. (Filed
as exhibit 10.39 to Western Gas Resources, Inc.'s Form 10-Q for the
three months ended March 31, 1995 and incorporated herein by
reference).
10.40 Form of Employment Agreement by and between Western Gas Resources,
Inc. and certain Executive Officers. (Filed as exhibit 10.40 to
Western Gas Resources, Inc.'s Form 10-Q for the three months ended
March 31, 1995 and incorporated herein by reference).
10.41 Receivables Purchase Agreement dated as of February 28, 1995 among
Western Gas Resources, Inc. (as seller) and Receivables Capital
Corporation (as purchaser) and Bank of America National Trust and
Savings Association (as agent). (Filed as exhibit 10.41 to Western
Gas Resources, Inc.'s Form 10-Q for the six months ended June 30,
1995 and incorporated herein by reference).
10.42 Joint Venture Agreement of Redman-Smackover Joint Venture. (Filed as
exhibit 10.42 to Western Gas Resources, Inc.'s Form 10-Q for the six
months ended June 30, 1995 and incorporated herein by reference).
10.43 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).
10.44 Amendment No. 1 to Receivables Purchase Agreement as of July 1, 1995
by and among Western Gas Resources, Inc., Receivables Capital
Corporation and Bank of America National Trust and Savings
Association. (Filed as exhibit 10.44 to Western Gas Resources, Inc.'s
Form 10-Q for the six months ended June 30, 1995 and incorporated
herein by reference).
10.45 Third Amendment to First Restated Loan Agreement (Revolver) dated
July 19, 1995. (Filed as exhibit 10.45 to Western Gas Resources,
Inc.'s Form 10-Q for the nine months ended September 30, 1995 and
incorporated herein by reference).
10.46 Letter Amendment No. 4 to Amended and Restated Master Shelf Agreement
dated July 28, 1995. (Filed as exhibit 10.46 to Western Gas
Resources, Inc.'s Form 10-Q for the nine months ended September 30,
1995 and incorporated herein by reference).
55
10.47 Fifth Amendment to Third Restated Loan Agreement (Term) dated July
19, 1995 (Filed as Exhibit 10.47 to Western Gas Resources, Inc.'s
Form 10-Q for the nine months ended September 30, 1995).
10.48 Fifth Amendment to the Master Shelf Agreement dated November 30,
1995 by and between Western Gas Resources, Inc. and Prudential
Insurance Company of America.
10.49 Second Amended and Restated Master Shelf Agreement effective January
31, 1996 by and between Western Gas Resources, Inc. and Prudential
Insurance Company of America.
10.50 Sixth Amendment to Third Restated Loan Agreement (Term) dated
November 29, 1995 by and among Western Gas Resources, Inc. and
NationsBank, as agent, and the Lenders.
10.51 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.
10.52 Senior Note Purchase Agreeement dated November 29, 1995 by and among
Western Gas Resources, Inc. and the Purchasers identified therein.
10.53 Fifth Amendment to First Restated Loan Agreement (Revolver) dated
March 22, 1996 by and among Western Gas Resources, Inc. and
NationsBank, as agent, and the Lenders.
10.54 Seventh Amendment to Third Restated Loan Agreement (Term) dated
March 22, 1996 by and among Western Gas Resources, Inc. and
NationsBank, as agent, and the Lenders.
10.55 First Amendment to Third Restated Loan Agreement (Term) as of
December 31, 1993 among Western Gas Resources, Inc. and NationsBank
of Texas, N.A. as agent and certain banks as Lenders (filed as
Exhibit 10.63 to Western Gas Resources, Inc.'s Form 10-K for the
year ended December 31, 1993).
11.1 Statement regarding computation of per share earnings.
21.1 List of Subsidiaries of Western Gas Resources, Inc.
23.1 Consent of Price Waterhouse LLP, independent accountants.
(b) Reports on Form 8-K:
A report on Form 8-K was filed on January 11, 1996 to notify the
Securities and Exchange Commission and the Company's stockholders of
the retirement of Bill M. Sanderson as President and Chief Operating
Officer and the election of Lanny F. Outlaw to those positions as
of April 1, 1996.
(c) Exhibits required by Item 601 of Regulation S-K. See (a) (3) above.
56
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 22, 1996.
WESTERN GAS RESOURCES, INC.
---------------------------
(Registrant)
By: /s/ Brion G. Wise
-------------------------
Brion G. Wise
Chairman of the Board and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.
/s/ Brion G. Wise
- ------------------------- Chairman of the Board, Chief March 22, 1996
Brion G. Wise Executive Officer and Director
/s/ Bill M. Sanderson
- ------------------------- President, Chief Operating March 22, 1996
Bill M. Sanderson Officer and Director
/s/ Walter L. Stonehocker
- ------------------------- Vice Chairman of the Board March 22, 1996
Walter L. Stonehocker and Director
- ------------------------- Director March 22, 1996
Richard S. Robinson
/s/ Dean Phillips
- ------------------------- Director March 22, 1996
Dean Phillips
/s/ Ward Sauvage
- ------------------------- Director March 22, 1996
Ward Sauvage
/s/ James A. Senty
- ------------------------- Director March 22, 1996
James A. Senty
- ------------------------- Director March 22, 1996
Joseph E. Reid
/s/ William J. Krysiak
- ------------------------- Vice President--Finance March 22, 1996
William J. Krysiak (Principal Financial and
Accounting Officer)
57