Back to GetFilings.com
March 17, 1997
Securities and Exchange Commission
450 5th Street, N.W.
Judiciary Plaza
Washington, D.C. 20549
Ladies and Gentlemen:
On behalf of Western Gas Resources, Inc. (the "Company"), please find enclosed
within this electronic submission via the EDGAR System, the Company's Form 10-K
for the year ended December 31, 1996. The appropriate copies have also been
filed with the New York Stock Exchange.
Very truly yours,
/S/ Diana L Laychak
- -------------------
Diana L. Laychak
Financial Reporting Manager
Enclosures
================================================================================
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[ X ] Annual report pursuant to section 13 or 15(d) of the Securities Exchange
Act of 1934 for the fiscal year ended December 31, 1996 or
[ ] Transition report pursuant to section 13 or 15(d) of the Securities
Exchange Act of 1934 [No Fee Required] for the transition period from
_________________ to _________________
Commission file number 1-10389
-------
WESTERN GAS RESOURCES, INC.
---------------------------
(Exact name of registrant as specified in its charter)
Delaware 84-1127613
-------- ----------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
12200 N. Pecos Street, Denver, Colorado 80234-3439
- --------------------------------------- ----------
(Address of principal executive offices) (Zip Code)
(303) 452-5603
--------------
Registrant's telephone number, including area code
No Changes
----------
(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 _____
-----
The aggregate market value of voting common stock held by non-affiliates of the
registrant on March 3, 1997 was $379,536,360.
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 21, 1997.
Indicate by check mark if disclosure of delinquent filers to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [_]
================================================================================
Western Gas Resources, Inc.
Form 10-K
Table of Contents
Part Item(s) Page
- ------ ---------- ----
I. 1 and 2. Business and Properties.............................................. 3
General........................................................... 3
Principal Facilities.............................................. 4
Gas Gathering, Processing, Storage and Transmission............... 6
Significant Acquisitions and Projects............................. 7
Marketing......................................................... 8
Producing Properties.............................................. 10
Competition....................................................... 10
Regulation........................................................ 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.......................... 23
9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.............................................. 50
III. 10. Directors and Executive Officers of the Registrant................... 50
11. Executive Compensation............................................... 50
12. Security Ownership of Certain Beneficial Owners and Management....... 50
13. Certain Relationships and Related Transactions....................... 50
IV. 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K..... 50
2
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
General
Western Gas Resources, Inc. (the "Company") is an independent gas gatherer and
processor and energy marketer providing a full range of services to its
customers from the wellhead to the delivery point. The Company designs,
constructs, owns and operates natural gas gathering, processing, treating and
storage facilities in major gas-producing basins in the Rocky Mountain, Mid-
Continent, Gulf Coast and Southwestern regions of the United States. The
Company connects producers' wells to its gathering systems for delivery to its
processing or treating plants, processes the natural gas to extract natural gas
liquids ("NGLs") and treats the natural gas in order to meet pipeline
specifications. The Company markets natural gas, NGLs and electric power
nationwide, providing risk management, storage, transportation, scheduling,
peaking and other services to a variety of customers. The Company also owns
certain producing properties, primarily in Louisiana, Texas and Wyoming.
Historically, the Company has derived over 95% of its revenues from the sale of
residue gas and NGLs. Set forth below are the Company's revenues by type of
operation (000s):
Year Ended December 31,
---------------------------------------------------------------
1996 % 1995 % 1994 %
---------- ------ ---------- ------ ---------- ------
Sale of residue gas.............. $1,440,882 68.9 $ 876,399 69.7 $ 707,869 66.6
Sale of NGLs..................... 561,581 26.9 331,760 26.4 309,358 29.1
Processing, transportation and
storage revenues............... 44,943 2.1 41,358 3.3 35,057 3.3
Sale of electric power........... 30,667 1.5 - - - -
Other, net....................... 12,936 .6 7,467 .6 11,205 1.0
---------- ----- ---------- ----- ---------- -----
$2,091,009 100.0 $1,256,984 100.0 $1,063,489 100.0
========== ===== ========== ===== ========== =====
The Company has expanded through acquisitions, internal project development and
increased marketing activity. This expansion has strengthened the Company's
position in major producing basins and increased its access to multiple natural
gas markets. The table below illustrates the Company's growth over the last
five years:
Average for the Year Ended
Average Average --------------------------------------
Residue NGL Gas Gas NGL
Gas Sales Sales Throughput Production Production
(MMcf/D) (MGal/D) (MMcf/D) (MMcf/D) (MGal/D)
---------- -------- ----------- ----------- ----------
December 31, 1991... 310 1,097 408 315 1,811
December 31, 1996... 1,794 3,744 1,171 912 2,265
% increase.......... 479 241 187 190 25
The Company's three-part business plan is designed to increase profitability
through: (i) investing in projects that complement and extend its core gas
gathering, processing and marketing business; (ii) expanding its energy
marketing services and sales volumes; and (iii) continuing to optimize the
profitability of existing operations. See further discussion in "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Business Strategy."
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 tables provide information concerning the Company's principal
facilities at December 31, 1996. The Company also owns and operates several
smaller treating, processing and transmission facilities located in the same
areas as its other facilities.
Average for the Year Ended
December 31, 1996
Gas Gas -------------------------------------------
Gathering Throughput Gas Gas NGL
Year Placed Systems Capacity Throughput Production Production
Plant Facilities (1) In Service Miles(2) (MMcf/D)(2) (MMcf/D)(3) (MMcf/D)(4) (MGal/D)(4)
- ------------------------------------ ---------- --------- ----------- ----------- ----------- -----------
Southern Region:
Texas
Midkiff /Benedum................. 1955 2,086 150 142 94 881
Giddings Gathering .............. 1979 655 80 67 57 86
Edgewood (5)(6).................. 1964 93 65 30 11 80
Perkins.......................... 1975 2,571 40 21 12 143
MiVida (5)....................... 1972 287 150 60 57 -
Gomez............................ 1971 302 280 158 155 -
Mitchell Puckett Gathering....... 1972 86 140 80 80 -
Crockett Gathering (7)........... 1973 - - 13 13 -
Rosita Treating ................. 1973 - 60 46 46 -
Louisiana
Black Lake....................... 1966 56 75 34 22 83
Toca (6)(8)...................... 1958 - 160 93 - 57
Northern Region:
Oklahoma
Chaney Dell/Lamont............... 1966 2,009 180 80 61 239
Arkoma........................... 1985 62 8 3 3 -
Westana (9)...................... 1986 258 45 59 54 58
Wyoming
Granger (6)(10).................. 1987 271 210 115 99 305
Red Desert (6)................... 1979 111 42 23 21 39
Lincoln Road (11)................ 1988 147 50 29 28 34
Hilight Complex (5)(6)........... 1969 628 80 34 28 84
Kitty/Amos Draw (6).............. 1969 304 17 11 8 46
Newcastle (6).................... 1981 145 5 2 1 18
Reno Junction (10)............... 1991 - - - - 50
Coal Seam Gathering.............. 1990 18 28 23 22 -
New Mexico
San Juan River (5)............... 1955 128 60 30 27 1
North Dakota
Williston (12)................... 1981 - - 7 5 25
Temple (13)...................... 1984 - - 3 2 7
Teddy Roosevelt (12)............. 1979 - - 3 2 12
Utah
Four Corners..................... 1988 104 15 4 3 7
Montana
Baker (14)....................... 1981 - - 1 1 10
------ ----- ----- --- -----
Total.......................... 10,321 1,940 1,171 912 2,265
====== ===== ===== === =====
- ---------------------------
Footnotes on following page.
4
Average for the
Year Ended
December 31,
1996
-------------
Gas Storage Pipeline Gas
Storage and Year Placed Transmission Capacity Capacity Throughput
Transmission Facilities (1) In Service Miles(2) (Bcf) (2) (MMcf/D) (2) (MMcf/D) (3)
- ------------------------------ ----------- --------------- --------- ------------- ------------
Katy Facility (15)............ 1994 17 19 - 304
MIGC (16)..................... 1970 214 - 45 48
MGTC (17)..................... 1963 250 - 18 9
--- -------- -- ---
Total........................ 481 19 63 361
=== ======== == ===
- -------------------
(1) The Company's interest in all facilities is 100% except for Midkiff/Benedum
(73%); Black Lake (69%); Lincoln Road (72%); Williston Gas Company
("Williston") (50%); Westana Gathering Company ("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, transmission miles, gas throughput capacity,
gas storage capacity and pipeline capacity are as of December 31, 1996.
(3) Aggregate wellhead natural gas volumes collected by a gathering system or
aggregate volumes delivered over the header at the Katy Hub and Gas Storage
Facility ("Katy Facility").
(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) Fractionation facility (capable of fractionating raw NGLs into end-use
products).
(7) The Crockett Gathering System was sold effective August 1, 1996.
(8) Straddle plant (a plant located near a transmission pipeline that processes
gas dedicated to or gathered by a pipeline company or another third party).
(9) Gas throughput and gas production in excess of gas throughput capacity is
unprocessed gas delivered directly to an unaffiliated pipeline.
(10) NGL production represents conversion of third-party feedstock to iso-
butane.
(11) Commencing in March 1996, the Company and its joint venture partner at the
Lincoln Road plant temporarily suspended processing operations at the
Lincoln Road plant and began processing the related gas at the Company's
Granger facility. This consolidation has resulted in lower overall plant
operating expenses for the combined systems. If volumes increase
substantially beyond Granger's capacity, the Lincoln Road plant might be
re-started.
(12) In January 1996, Koch Hydorcarbon Company, which operated 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. The closing of the sale occurred on
December 6, 1996.
(13) The Temple facility was sold effective May 1, 1996.
(14) The Baker facility was sold effective December 31, 1996.
(15) Hub and gas storage facility.
(16) MIGC is an interstate pipeline located in Wyoming and is regulated by the
Federal Energy Regulatory Commission ("FERC").
(17) MGTC is a public utility located in Wyoming and is regulated by the Wyoming
Public Service Commission.
Capital expenditures related to existing operations are expected to be
approximately $154.4 million during 1997, consisting of the following: capital
expenditures related to gathering, processing and pipeline assets are expected
to be $112.8 million, of which $99.9 million will be used for new connects,
system expansions and asset consolidations and $12.9 million for maintaining
existing facilities. The Company expects capital expenditures on exploration
and production activities, the Katy Facility and miscellaneous items to be $36.4
million, $3.3 million and $1.9 million, respectively.
Gas Gathering, Processing, Storage and Transmission
Gas Gathering and Processing
The Company contracts with producers to gather raw natural gas ("natural gas")
from individual wells located near its plants. Once a contract has been
executed, the Company connects wells to gathering lines through which the
natural gas is delivered to a processing plant or treating facility. At a
processing plant, the natural gas is compressed, unfractionated NGLs are
extracted, and the remaining dry gas ("residue gas") is treated to meet pipeline
quality specifications. Seven of the Company's processing plants
5
can further separate, or fractionate, the mixed NGL stream into ethane, propane,
normal butane and natural gasoline to obtain a higher value for the NGLs, and
four of the Company's plants are able to process and treat natural gas
containing hydrogen sulfide or other impurities which require removal prior to
transportation. In addition, the Company has two facilities which convert normal
butane into iso-butane. At a treating facility, dry gas, which does not contain
liquids that can economically be extracted, is treated to meet pipeline quality
specifications by removing hydrogen sulfide or carbon dioxide.
The Company continually acquires additional dedicated natural gas supplies to
maintain or increase throughput levels to offset natural production declines in
dedicated volumes. Such natural gas supplies are obtained by purchasing
existing systems from third parties, by connecting additional wells or through
internally developed projects. 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 or development
of additional systems. Historically, the Company has connected additional
reserves that more than offset production from reserves dedicated to existing
facilities. However, certain individual plants have experienced declines in
dedicated reserves. In 1996, including the reserves associated with the
Company's joint ventures, the Company connected new reserves to its gathering
systems to replace approximately 115% of 1996 production. On a Company-wide
basis, dedicated reserves, including revisions to previous estimates, increased
from approximately 2.7 Tcf as of December 31, 1995 to approximately 2.8 Tcf at
December 31, 1996.
Substantially all gas flowing through the Company's facilities is supplied under
long-term contracts providing for the purchase, treating or processing of
natural gas for periods ranging from five to twenty years, using three basic
contract types. Approximately 40% of the Company's gas throughput for the year
ended December 31, 1996 was purchased under percentage-of-proceeds agreements in
which the Company is typically responsible for arranging for the transportation
and marketing of the residue gas and NGLs. Approximately 70% of the company's
plant facilities' gross margin (revenues at the plants less product purchases)
were from percentage-of-proceeds contracts for the year ended December 31, 1996.
The price paid to producers is a specified percentage of the net proceeds
received from the sale of the residue gas and the NGLs. This type of contract
permits the Company and the producers to share proportionally in price changes.
Approximately 35% of the Company's gas throughput for the year ended December
31, 1996 was gathered under contracts that are primarily fee-based whereby the
Company receives a set fee for each Mcf of gas gathered. This type of contract
provides the Company with a steady revenue stream that is not dependent on
commodity prices, except to the extent that low prices may cause a producer to
curtail production. Approximately 10% of the Company's plant facilities' gross
margin (revenues at the plants less product purchases) were from fee-based
contracts for the year ended December 31, 1996. The percentage of fee-based
contracts is expected to increase in 1997 once the Bethel facility is
operational. See further discussion in "Significant Acquisitions and Projects."
Approximately 25% of the Company's gas throughput for the year ended December
31, 1996 was processed under contracts that combine gathering and compression
fees with "keep-whole" arrangements or wellhead purchases. Typically, producers
are charged a gathering and compression fee based upon volume. In addition, the
Company retains a predetermined percentage of the NGLs recovered by the
processing facility and keeps the producers whole by returning to the producers
at the tailgate of the plant an amount of residue gas equal on a Btu basis to
the natural gas received at the plant inlet. The "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 unfavorably affected. Approximately 20% of the Company's
plant facilities' gross margin (revenues at the plants less product purchases)
were from this type of contract.
Storage and Transmission
In order to enhance the Company's residue gas marketing activities, it
constructed the Katy Facility. The Company commenced operations of the Katy
Facility in February 1994. The Katy Facility, which is located approximately 20
miles from Houston, Texas, utilizes a partially depleted natural gas reservoir
with 19 Bcf of working gas capacity and a pipeline header system, currently
connected to 11 pipelines, which has the capability to deliver up to 400 MMcf
per day of residue gas from the reservoir. Lease acquisition and construction
costs incurred through the commencement of operations, including pad gas,
approximated $106.1 million. See "Marketing - Residue Gas."
The Company owns and operates MIGC, an interstate pipeline located in the Powder
River Basin in Wyoming and MGTC, an intrastate pipeline located in Northeast
Wyoming. As part of the Company's plan to expand its Powder River Basin coal
seam operations, MIGC is currently seeking approval from the FERC to increase
its pipeline capacity from 45 MMcf per day to 90 MMcf per day. The Company
anticipates receiving such approval during the second quarter of 1997. See
further discussion in "Significant Acquisitions and Projects."
6
Significant Acquisitions and Projects
The Company's significant acquisitions and projects since January 1, 1994 are:
Bethel Facility (Cotton Valley Pinnacle Reef)
The Company is currently constructing the Bethel facility in East Texas that
will gather gas from the Cotton Valley Pinnacle Reef trend. Based upon currently
anticipated gas compositions, this facility could treat up to approximately 350
MMcf per day. The Bethel facility has been designed to accommodate incremental
expansions, depending upon the success of continued development in the trend.
Construction of the Bethel facility began in September 1996. The facility is
expected to commence operations at a throughput capacity of approximately 180
MMcf per day in June 1997. The initial phase is expected to be completed to
reach the 350 MMcf per day of throughput capacity during the last half of 1997,
approximately 60 days after the receipt of a pending air quality permit. The
initial phase of construction is expected to cost approximately $67.8 million.
During the year ended December 31, 1996, the Company has expended approximately
$10.1 million for such facility. Long-term gathering and treating agreements
have been signed with several producers, including Sonat Exploration Company,
UMC Petroleum Corporation and Broughton Associates Joint Venture, relating to
their interests in the Cotton Valley Pinnacle Reef trend. The agreements cover
specified areas of dedication aggregating approximately 500,000 acres of
previously undedicated interests. However, due to uncertainties related to
construction costs, possible delays in permitting and other conditions outside
the Company's control, there can be no assurance that this project will develop
as rapidly as currently anticipated. In addition, a portion of the production
that is anticipated to be gathered and treated at the Bethel facility is
expected to be produced from prospects that have not yet been drilled and
completed, and there can be no assurance of successful completion of wells in
these prospects.
Coal Seam Gathering System Expansion
The Company plans to expand its Powder River Basin coal seam natural gas
gathering system and develop its own coal seam gas reserves in Wyoming. The
Company has acquired drilling rights in the vicinity of known coal seam
production on approximately 140,000 gross acres. The Company and other operators
in the area have established production from wells drilled to depths of 200 to
700 feet. The gathering and completion costs associated with such drilling
activities are expected to total approximately $75,000 per well. The Company
will utilize its existing dry gas gathering system and interstate pipeline to
transport this pipeline quality gas to market. The Company's capital budget
provides for expenditures of approximately $65.5 million during the next five
years. This capital budget includes approximately $42.7 million for drilling
costs, production equipment and purchase of operating wells and undeveloped
acreage. The remainder is to be used primarily for compression equipment.
However, because of drilling and other uncertainties beyond the Company's
control, there can be no assurance that this level of capital expenditure will
be achieved. During the year ended December 31, 1996, the Company has expended
approximately $6.9 million on this project. In March 1997, the Company purchased
certain operating wells and undeveloped acreage from a producer in the Powder
River Basin for $12.4 million in cash and an additional payment of approximately
$7.9 million payable in January 1998.
Northern Acquisition
In July 1995, the Company entered into an agreement to purchase eight West Texas
gathering systems, consisting of approximately 230 miles of gathering lines in
the Permian Basin, from Transwestern Gathering Company and Enron Permian
Gathering, Inc. 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.
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., 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 is the managing venturer with a 50%
ownership interest.
7
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 an agreement with Oasis for
100 MMcf per day of firm transportation service on its intrastate pipeline
through December 1999. The Company has installed a 200 MMcf per day pipeline
interconnection between this pipeline and the Katy Facility. As part of the
long-term plan for utilization of the assets, the Company has sold various non-
strategic assets associated with this purchase.
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 1996, the Company sold its Temple and Baker facilities
and the remaining non-strategic assets associated with the Oasis acquisition.
Commencing in March 1996, the Company and its joint venture partner at the
Lincoln Road 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. This consolidation has resulted in lower overall plant
operating expenses for the combined systems. In January 1996, Koch Hydrocarbon
Company, which operated 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 were $2.4 million, of which the Company received $1.5 million.
The closing of the sale occurred in December 1996, at which time the operation
of Williston and the Company's Teddy Roosevelt facility ceased and the remaining
assets are being salvaged. 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.
Marketing
Residue 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. Since 1991, the Company's residue
gas sales volumes have increased by 479% to 1.8 Bcf per day for the year ended
December 31, 1996, primarily as a result of the increase in third-party sales.
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.
The Company intends to continue to expand its residue gas marketing and third-
party sales, particularly to industrial and commercial end-users. 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 the Midwest and
Northeast. 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 expand its ability to provide
market services and arbitrage price differentials, the Company constructed the
Katy Facility. The ability to withdraw gas from the Katy Facility on short
notice positions the Company to market residue gas to LDCs and other customers
that need a reliable yet variable supply of residue gas. The Katy Facility's
header system allows the Company to bypass certain transportation bottlenecks
and enhances flexibility in its marketing operations.
The Company held approximately 10.4 Bcf of residue gas in storage for such
purposes at an average cost of $1.84 per Mcf at December 31, 1996 compared to
12.8 Bcf at an average cost of $1.65 per Mcf at December 31, 1995, primarily at
the Katy Facility. At December 31, 1996, the Company had hedging contracts in
place for anticipated sales for approximately 10.0 Bcf of
8
stored gas at a weighted average price of $2.12 per Mcf for the stored
inventory. See further discussion in "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Liquidity and Capital
Resources -Risk Management Activities."
The Company has a three-year, winter-peaking gas purchase and sales agreement
with a major utility in East Texas, expiring in March 1999, which designates the
Katy Facility as the primary delivery point. Under the agreement, the utility
has the right to purchase, during each year of the contract, up to approximately
100 MMcf per day and 70 MMcf per day of residue gas in November and March,
respectively, and approximately 140 MMcf per day of residue gas in December,
January and February, at a monthly index price plus a fixed charge. The
agreement calls for a minimum charge to be paid to the Company for each contract
term, whether or not delivery is taken. This minimum charge is calculated based
upon five Bcf of annual storage during each fiscal year of the contract term.
In February 1995, the Company entered into a long-term firm storage and
transportation agreement with a St. Louis-based LDC that expires in March 2000.
Under the agreement, the Company has leased approximately three Bcf of storage
capacity of the Katy Facility to the LDC. The gas will principally serve local
distribution requirements of the LDC's customers in central Missouri.
During the year ended December 31, 1996, the Company sold residue gas to
approximately 440 end-users, pipelines, LDCs and other customers. No single
customer accounted for more than 5.5% of consolidated revenues for the year
ended December 31, 1996.
NGL Marketing
The Company markets NGLs (ethane, propane, iso-butane, normal butane, natural
gasoline and condensate) produced at its plants and purchased from third parties
in the Rocky Mountain, Mid-Continent, Gulf Coast and Southwestern regions of the
United States. A majority of the Company's production of NGLs moves to the Gulf
Coast area, which is the largest NGL market in the United States. Through the
development of end-use markets and distribution capabilities, the Company seeks
to ensure that products from its plants move on a reliable basis, avoiding
curtailment of production.
Consumption of NGLs is primarily determined by various end-user markets
including the petrochemical industry, the petroleum refining industry and the
retail and industrial fuel markets. As an example, the petrochemical industry
uses ethane, propane, normal butane and natural gasoline as feedstocks in the
production of ethylene, which is used in the production of various plastics
products. Over the last several years, the petrochemical industry has increased
its use of NGLs as a major feedstock and is projected to require an additional
6,300 MGal per day to 8,400 MGal per day of NGL supply by 1998, an increase of
approximately 15% to 20%. Further, propane is 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 for its NGL marketing activities, with no prices set on a
firm basis for more than a 30-day period. Although some existing contracts do
commit the Company for periods as long as a year, prices are typically
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. The
Company held NGLs in storage of 16,080 MGal at an average cost of $.42 per
gallon and 15,816 MGal at an average cost of $.31 per gallon at December 31,
1996 and December 31, 1995, respectively, at various third-party storage
facilities. The Company generally intends that stored NGLs turn over on an
annual basis.
For the year ended December 31, 1996, NGL sales averaged 3,744 MGal per day, an
increase from 1,097 MGal per day in 1991, primarily due to acquisitions during
the five-year period. Sales were made to approximately 150 different customers,
and no single customer accounted for more than 2.5% of the Company's
consolidated revenues for the year ended December 31, 1996. Revenues are also
derived from contractual marketing fees charged to some producers for NGL
marketing services. For the year ended December 31, 1996, such fees were less
than 1% of the Company's consolidated revenues.
Power Marketing
In July 1996, the FERC issued its final order requiring investor-owned electric
utilities to provide open access for wholesale transmission. This action allows
companies to participate in a market previously controlled by electric
utilities. During the first half of 1996, the Company created the staffing and
contractual infrastructure necessary to market electric power on a nationwide
basis. The Company currently trades electric power in the wholesale market and
enters into transactions that arbitrage the value of residue gas and electric
power. The Company intends to expand its marketing efforts to reach industrial
end-users as these
9
markets become available. The Company believes its expertise in marketing
residue gas in a deregulated environment, its expanding customer base and its
firm supplies of residue gas and NGL products will allow it to compete
effectively in this emerging market.
The Company believes that the anticipated deregulation by states of retail power
marketing will offer the Company significant opportunities to offer both residue
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 1995, the Company received a
certificate from the FERC authorizing it to sell electric power at the wholesale
level. At December 31, 1996, the Company had nine employees dedicated to power
marketing. There is no assurance that the retail electric power marketing
industry will develop as the Company anticipates or that the Company will be
successful in obtaining profitable wholesale or retail power marketing
operations.
Producing Properties
Revenues derived from the Company's producing properties comprised approximately
1.6% of revenues for the year ended December 31, 1996. 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 Austin Chalk formation in southeast Texas, the
Powder River Basin in northeast Wyoming, the Jonah Field in southwest Wyoming,
the San Juan Basin in southwest Colorado and the Sandwash Basin in northwest
Colorado. The Company also owns various working interests in 13 wells in the
Smackover formation through Redman Smackover.
Reserve estimates are subject to numerous uncertainties inherent in the
estimation of quantities of proved reserves and in the projection of future
rates of production and the timing of development expenditures. The accuracy of
such estimates is a function of the quality of available data and of engineering
and geological interpretation and judgment. Estimates of economically
recoverable reserves and of future net cash flows expected therefrom prepared by
different engineers or by the same engineers at different times may vary
substantially. Results of subsequent drilling, testing and production may cause
either upward or downward revisions of previous estimates. Further, the volumes
considered to be commercially recoverable fluctuate with changes in prices and
operating costs. Any significant revision of reserve estimates could materially
adversely affect the Company's financial condition and results of operations.
Competition
The Company competes with other companies in the gathering, processing and
marketing businesses both for supplies of natural gas and for customers for its
residue gas and NGLs. Competition for natural gas supplies is primarily based
on efficiency, reliability, availability of transportation and ability to obtain
a satisfactory price for the producers' natural gas. Competition for customers
is primarily based upon reliability and price of deliverable residue gas and
NGLs. For customers that have the capability of using alternative fuels, such
as oil and coal, the Company also competes based primarily on price against
companies capable of providing such alternative fuels. The Company's
competitors for obtaining additional natural gas supplies, for gathering and
processing natural gas and for marketing residue gas and NGLs include national
and local gas gatherers, brokers, marketers and distributors of various size,
financial resources and experience. 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 continue to
stabilize. However, there is no assurance that the Company will be able to
expand its current end-use business.
Regulation
The purchase and sale of natural gas and the fees received for gathering and
processing by the Company have generally not been subject to regulation, and
therefore, except as constrained by competitive factors, the Company has
considerable pricing flexibility. Many aspects of the gathering, processing,
marketing and transportation of natural gas and NGLs by the Company, however,
are subject to federal, state and local laws and regulations which can have a
significant impact upon the Company's overall operations.
As a processor and marketer of natural gas, the Company depends on the
transportation and storage services offered by various interstate and intrastate
pipeline companies for the delivery and sale of its own gas supplies as well as
those it processes and/or markets for others. Both the performance of
transportation and storage services by interstate pipelines, and the rates
charged for such services, are subject to the jurisdiction of the FERC under the
Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The availability
of interstate transportation and storage service necessary to enable the
10
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.
Generally, gathering and processing prices are not regulated by the FERC or any
state agency. However, in May 1995, Oklahoma Corporation Commission was granted
limited authority in certain circumstances, after the filing of a complaint by a
producer, to compel a gas gatherer to provide open access gathering and to set
aside unduly discriminatory gathering fees. The Texas Railroad Commission is in
the process of reviewing Texas regulation of gathering. In addition, the state
legislatures and regulators in certain other states in which the Company gathers
gas are also contemplating additional regulation of gas gathering. The Company
does not believe that any of the proposed legislation of which it is aware is
likely to have a material adverse effect on the Company's financial position or
results of operation. However, the Company cannot predict what additional
regulations the states may impose on gathering.
In 1995, the Company was granted authorization by the FERC permitting it to sell
electric power at the wholesale level, and since that time the Company has
actively engaged in numerous power marketing transactions with electric
utilities, power marketers and others. These activities have been greatly
facilitated by the FERC's issuance during 1996, of a final rule (Order Nos. 888,
et. seq.) requiring investor-owned electric utilities to provide "open access"
- --------
service to parties requesting use of their electric transmission systems, and
such activities may be further benefitted by the restructuring of retail power
systems at the state level. Currently, a number of states are either
considering or have enacted legislation concerning various forms of retail power
system restructurings; however, the timing and ultimate outcome of the
implementation of these state actions are presently uncertain. In addition,
wholesale power restructuring and judicial review, and the outcome of these
proceedings - and their ultimate effect on the Company's power marketing
activities - is too speculative to predict at this time.
Employees
At December 31, 1996, the Company employed 920 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, 1996.
11
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
As of March 3, 1997, there were 32,112,785 shares of Common Stock outstanding
held by 381 holders of record. The Common Stock is traded on the New York Stock
Exchange under the symbol "WGR". The following table sets forth quarterly high
and low sales prices as reported by the NYSE Composite Tape for the quarterly
periods indicated:
HIGH LOW
------- -------
1996
Fourth Quarter................................... $19 3/8 $13 7/8
Third Quarter.................................... 16 3/8 13 1/8
Second Quarter................................... 16 3/4 13 1/2
First Quarter.................................... 16 5/8 11 1/8
1995
Fourth Quarter................................... 17 5/8 15
Third Quarter.................................... 18 1/4 15 1/2
Second Quarter................................... 24 1/4 16 5/8
First Quarter.................................... $22 1/8 $16 3/4
The Company paid annual dividends on the Common Stock aggregating $.20 per share
during the years ended December 31, 1996 and 1995. The Company has declared a
dividend of $.05 per share of Common Stock for the quarter ending March 31, 1997
to holders of record as of such date. Declarations of dividends on the Common
Stock are within the discretion of the Board of Directors. In addition, the
Company's ability to pay dividends is restricted by certain covenants in its
financing facilities, the most restrictive of which prohibits declaring or
paying dividends after December 31, 1995 that exceed, in the aggregate, the sum
of $10 million plus 50% of the Company's cumulative consolidated net income
earned after December 31, 1995 plus 50% of the net proceeds received by the
Company after December 31, 1995 from the sale of any equity securities. The
dividends declared in the fourth quarter of 1995, payable in 1996, are excluded
from this calculation. At December 31, 1996, availability under this covenant
amounted to $56.2 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 1996. The data for the three years ended
December 31, 1996 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, 1993 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,
----------------------------------------------------------------
1996 1995 1994 1993 1992
---------- ---------- ---------- ---------- --------
(000s, except per share amounts and operating data)
Statement of Operations:
Revenues.................................... $2,091,009 $1,256,984 $1,063,489 $ 932,338 $600,116
Gross profit (a)............................ 105,479 75,211 72,556 92,012 88,192
Income (loss) before income taxes........... 41,631 (8,266) (b) 11,524 55,631 58,445
Provision (benefit) for income taxes........ 13,690 (2,158) 4,160 17,529 18,757
Net income (loss)........................... 27,941 (6,108) (b) 7,364 38,102 39,688
Earnings (loss) per share of common
stock...................................... .66 (.84) (.19) 1.25 1.43
Cash Flow Data:
Net cash provided by operating activities... 168,266 86,373 31,866 107,116 96,655
Capital expenditures........................ 74,555 78,521 100,540 492,328 67,021
Balance Sheet Data
(at year end):
Total assets................................ 1,361,631 1,193,997 1,167,362 1,114,748 582,188
Long-term debt.............................. 379,500 529,500 493,000 547,000 157,000
Stockholders' equity........................ 480,467 371,909 436,683 314,387 287,021
Dividends declared per share of common
stock...................................... $ .20 $ .20 $ .20 $ .20 $ .20
Operating Data:
Average gas sales (MMcf/D).................. 1,794 1,572 1,097 755 442
Average NGL sales (MGal/D).................. 3,744 2,890 2,970 2,941 2,400
Average gas volumes gathered (MMcf/D)....... 1,171 1,020 934 804 669
Facility capacity (MMcf/D).................. 1,940 1,907 1,560 1,586 1,177
Average gas prices ($/Mcf).................. $ 2.19 $ 1.53 $ 1.77 $ 2.02 $ 1.72
Average NGL prices ($/Gal).................. $ .41 $ .31 $ .28 $ .31 $ .32
- ---------------------------
(a) Excludes selling and administrative, interest, restructuring and income tax
expenses.
(b) In 1995, the Company adopted Statement of Financial Accounting Standards
No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-
Lived Assets to be Disposed of" ("SFAS No. 121"), which resulted in the
recognition of a non-cash loss of $17.6 million, pre-tax, and $12.4
million, after-tax. Also, the Company implemented a cost reduction program
to reduce operating and selling and administrative expenses. As a result of
this program, a $2.1 million, pre-tax, and $1.3 million, after-tax,
restructuring charge was incurred, primarily related to employee severance
costs.
13
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion and analysis relates to factors that have affected the
consolidated financial condition and results of operations of the Company for
the three years ended December 31, 1996. Certain prior year amounts have been
reclassified to conform to the presentation used in 1996. 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, 1996 compared to year ended December 31, 1995
(000s, except per share amounts and operating data)
Year Ended
December 31,
-------------------------- Percent
1996 1995 Change
------------ ----------- ------
Financial results:
Revenues.................................... $2,091,009 $1,256,984 66
Gross profit................................ 105,479 75,211 40
Net income (loss)........................... 27,941 (6,108) -
Earnings (loss) per share of common stock... .66 (.84) -
Net cash provided by operating activities... $ 168,266 $ 86,373 95
Operating data:
Average gas sales (MMcf/D).................. 1,794 1,572 14
Average NGL sales (MGal/D).................. 3,744 2,890 30
Average gas prices ($/Mcf).................. $ 2.19 $ 1.53 43
Average NGL prices ($/Gal).................. $ .41 $ .31 32
Net income increased $34.0 million and net cash provided by operating activities
increased $81.9 million for the year ended December 31, 1996 compared to 1995.
The increase in net income for the year was partially due to a $12.4 million,
after-tax, impairment loss recorded on October 1, 1995 in connection with the
adoption of SFAS No. 121 and a $1.3 million, after-tax, restructuring charge the
Company recorded in May 1995 relating to its cost reduction program. In
addition, net income was positively affected by higher revenues attributable to
increases in prices and volumes, partially offset by higher product purchase
costs associated with the Company's third-party residue gas sales.
Revenues from the sale of residue gas increased approximately $564.5 million for
the year ended December 31, 1996 compared to 1995. Average gas sales volumes
increased 222 MMcf per day to 1,794 MMcf per day for the year ended December 31,
1996 compared to 1995, largely due to an increase of approximately 225 MMcf per
day in the sale of residue gas purchased from third parties, partially offset by
decreased sales at the Company's Black Lake facility. Average gas prices
realized by the Company increased $.66 per Mcf to $2.19 per Mcf for the year
ended December 31, 1996 compared to 1995. Included in the realized residue gas
price was approximately $7.2 million of loss recognized in the year ended
December 31, 1996 related to futures positions on equity volumes. The Company
has entered into futures positions for a portion of its equity gas for 1997. See
further discussion in "Liquidity and Capital Resources - Risk Management."
Revenues from the sale of NGLs increased approximately $229.8 million for the
year ended December 31, 1996 compared to 1995. Average NGL sales volumes
increased 854 MGal per day to 3,744 MGal per day for the year ended December 31,
1996 compared to 1995, largely due to an increase of approximately 715 MGal per
day in the sale of NGLs purchased from third parties. Average NGL prices
realized by the Company increased $.10 per gallon to $.41 per gallon for the
year ended December 31, 1996 compared to 1995. Included in the realized NGL
price was approximately $11.6 million of loss recognized in the year ended
December 31, 1996 related to futures positions on equity volumes. The Company
has entered into futures positions for a portion of its equity production for
1997. See further discussion in "Liquidity and Capital Resources - Risk
Management."
Revenue associated with electric power marketing was approximately $30.7
million; the Company entered this market at the end of 1995.
14
Other net revenue increased approximately $5.5 million for the year ended
December 31, 1996 compared to 1995. The increase was largely due to an increase
of approximately $2.9 million in partnership income, primarily attributable to
Redman Smackover, and a $1.9 million gain recognized on the sale of the Temple
facility.
The increase in product purchases corresponds to the increase in third-party
product sales. Combined product purchases as a percentage of residue gas, NGL
and electric power sales increased from 87% to 89% for the year ended December
31, 1996 compared to 1995. The increased product purchase percentage is a
continuing trend based upon the growth of third-party sales, which typically
have lower margins than sales of the Company's equity production. 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 continue to stabilize. However, there is no assurance that the Company
will be able to expand its current end-use business.
Selling and administrative expense increased $2.8 million for the year ended
December 31, 1996 compared to 1995, primarily as a result of growth in the
Company's marketing operations and higher benefit costs.
Depreciation, depletion and amortization decreased $2.2 million for the year
ended December 31, 1996 compared to the prior year. The decrease was
attributable to decreases in production related to the Company's oil and gas
properties, primarily at the Company's Black Lake facility. In addition, the
Company recorded a $17.6 million write-down of certain oil and gas assets and
plant facilities in the fourth quarter of 1995 in connection with its adoption
of SFAS No. 121. The lower asset values contributed to the reduction in
depreciation, depletion and amortization expense for the year ended December 31,
1996. These decreases were offset by increases related to various property
additions.
Interest expense decreased $2.7 million for the year ended December 31, 1996
compared to the prior year. The decrease was primarily due to the use of
improved cash flows from operations and the use of the Company's net proceeds
from the November 1996 public offering of 6,325,000 shares of Common Stock to
reduce indebtedness under the Revolving Credit Facility.
The provision for income taxes for the year ended December 31, 1996 increased
$15.8 million primarily due to the increase in pre-tax income for the year.
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
Gross profit.......................................... 75,211 72,556 4
Net income (loss)..................................... (6,108) 7,364 -
Earnings (loss) per share of common stock............. (.84) (.19) (342)
Net cash provided by operating activities............. $ 86,373 $ 31,866 171
Operating data:
Average gas sales (MMcf/D)............................ 1,572 1,097 43
Average NGL sales (MGal/D)............................ 2,890 2,970 (3)
Average gas prices ($/Mcf)............................ $ 1.53 $ 1.77 (14)
Average NGL prices ($/Gal)............................ $ .31 $ .28 11
Net income (loss) 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 $12.4
million, after-tax, impairment loss recorded in connection with the adoption of
SFAS No. 121 and a $1.3 million, after-tax, restructuring charge the Company
recorded in May 1995 relating to its cost reduction program. In addition, net
income (loss) 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
15
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
realized by the Company decreased $.24 per Mcf to $1.53 per Mcf for the year
ended December 31, 1995 compared to 1994. Included in the realized residue gas
price was approximately $10.0 million of gain recognized in the year ended
December 31, 1995 related to futures positions on equity volumes.
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 realized 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.
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 three percentage points to 87% for the year ended
December 31, 1995 compared to 1994. The rising residue 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. The increase was primarily
attributable to the Oasis assets, additional depreciation, depletion and
amortization 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 its 7.25% Cumulative Perpetual Convertible
Preferred Stock.
Liquidity and Capital Resources
The Company's sources of liquidity and capital resources historically have been
net cash provided by operating activities, funds available under its financing
facilities and proceeds from offerings of equity securities. In the past, these
sources have been sufficient to meet its needs and finance the growth of the
Company's business. The Company can give no assurance that the historical
sources of liquidity and capital resources will be available for future
development and acquisition projects, and it may be required to seek
alternative financing sources. Net cash provided by operating activities is
primarily affected by product prices and sales of inventory, the Company's
success in increasing the number and efficiency of its facilities and the
volumes of natural gas processed by such facilities, as well as the margin on
third-party product purchased for resale. The Company's continued growth will
be dependent upon success in the areas of marketing, additions to dedicated
plant reserves, acquisitions and new project development.
The Company believes that the amounts available to be borrowed under the
Revolving Credit Facility, together with cash provided by operating activities,
will provide it with sufficient funds to connect new reserves, maintain its
existing facilities and complete its current capital expenditure program.
Depending on the timing and the amount of the Company's future projects, it may
be required to seek additional sources of capital. The Company's ability to
secure such capital is restricted by its credit facilities, although it may
request additional borrowing capacity from its lenders, seek waivers from its
lenders to permit it to borrow funds
16
from third parties, seek replacement credit facilities from other lenders, use
stock as a currency for an acquisition, sell existing assets or a combination of
such alternatives. While the Company believes that it would be able to secure
additional financing, if required, no assurance can be given that it will be
able to do so or as to the terms of any such financing. The Company also
believes that cash provided by operating activities will be sufficient to meet
its debt service and preferred stock dividend requirements in 1997.
The Company's sources and uses of funds for the year ended December 31, 1996 are
summarized as follows (000s):
Sources of funds:
Borrowings under revolving credit facility....... $1,035,377
Net cash provided by operating activities........ 168,266
Net proceeds from the issuance of common stock... 96,376
Other............................................ 9,218
----------
Total sources of funds........................... $1,309,237
==========
Uses of funds:
Payments on revolving credit facility............ $1,172,877
Payments on long-term debt....................... 12,500
Capital investments.............................. 74,555
Dividends paid................................... 15,596
----------
Total uses of funds.............................. $1,275,528
==========
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 approximately
10.4 Bcf of residue gas in storage for such purposes at an average cost of $1.84
per Mcf at December 31, 1996 compared to 12.8 Bcf at an average cost of $1.65
per Mcf at December 31, 1995, primarily at the Katy Facility. At December 31,
1996, the Company had hedging contracts in place for anticipated sales for
approximately 10.0 Bcf of stored gas at a weighted average price of $2.12 per
Mcf for the stored inventory. The Company held NGLs in storage of 16,080 MGal
at an average cost of $.42 per gallon and 15,816 MGal at an average cost of $.31
per gallon at December 31, 1996 and December 31, 1995, respectively, at various
third-party storage facilities. At December 31, 1996, the Company did not have
any hedging contracts in place associated with NGLs in storage.
The Company has been successful overall in replacing production with new
reserves. Historically, the Company has connected additional reserves that more
than offset production from reserves dedicated to existing facilities. However,
certain individual plants have experienced declines in dedicated reserves. In
1996, including the reserves associated with the Company's joint ventures, the
Company connected new reserves to its gathering systems to replace approximately
115% of 1996 production. On a Company-wide basis, dedicated reserves, including
revisions to previous estimates, increased from approximately 2.7 Tcf as of
December 31, 1995 to approximately 2.8 Tcf at December 31, 1996.
The Company has effective shelf registration statements filed with the
Securities and Exchange Commission for an aggregate of $200 million of debt
securities and preferred stock (along with the shares of common stock, if any,
into which such securities are convertible) and $62 million of debt securities,
preferred stock or common stock.
In November 1996, the Company issued 6,325,000 shares of Common Stock at a
public offering price of $16.25 per share. The net proceeds to the Company of
$96.4 million were primarily used to reduce indebtedness under the Revolving
Credit Facility.
Risk Management Activities
The Company's commodity price risk management program has two primary
objectives. The first goal is to preserve and enhance the value of the Company's
equity volumes of natural gas and NGLs with regard to the impact of commodity
price movements on cash flow, net income and earnings per share in relation to
those anticipated by the Company's operating budget. The second goal is to
manage price risk related to the Company's physical natural gas, NGL and power
marketing activities to protect profit margins. This risk relates to hedging
fixed price purchase and sale
17
commitments, preserving the value of storage inventories, reducing exposure to
physical market price volatility and providing risk management services to a
variety of customers.
The Company utilizes a combination of fixed price forward contracts, exchange-
traded futures and options, as well as fixed index swaps, basis swaps and
options traded in the over-the-counter ("OTC") market. These instruments allow
the Company to preserve value and protect margins because gains or losses in the
physical market are offset by corresponding losses or gains in the value of the
financial instruments.
The Company uses futures, swaps and options to reduce price risk and basis
risk. Basis is the difference in price between the physical commodity being
hedged and the price of the futures contract used for hedging. Basis risk is
the risk that an adverse change in the futures market will not be completely
offset by an equal and opposite change in the cash price of the commodity being
hedged. Basis risk exists in natural gas primarily due to the geographic price
differentials between cash market locations and futures contract delivery
locations.
The Company enters into futures transactions on the New York Mercantile Exchange
("NYMEX") and the Kansas City Board of Trade and through OTC swaps and options
with creditworthy counterparties consisting primarily of financial institutions
and other natural gas companies. The Company conducts its standard credit
review of OTC counterparties and has agreements with such parties that contain
collateral requirements. The Company generally uses standardized swap
agreements that allow for offset of positive and negative exposures. OTC
exposure is marked to market daily for the credit review process. The Company's
OTC credit risk exposure is partially limited by its ability to require a margin
deposit based upon the mark-to-market value of the counterparties' net exposure.
The Company is subject to margin deposit requirements under these same
agreements. In addition, the Company is subject to similar margin deposit
requirements for its NYMEX counterparties related to its net exposures.
The use of financial instruments may expose the Company to the risk of financial
loss in certain circumstances, including instances when (i) equity volumes are
less than expected, (ii) the Company's customers fail to purchase or deliver the
contracted quantities of natural gas or NGLs, or (iii) the Company's OTC
counterparties fail to perform. To the extent that the Company engages in
hedging activities, it may be prevented from realizing the benefits of favorable
price changes in the physical market. However, it is similarly insulated
against decreases in such prices.
As of December 31, 1996, the Company held a notional quantity of approximately
250 Bcf of natural gas futures, swaps and options extending from January 1997 to
October 1998 with an average portfolio life of approximately four months. This
was comprised of approximately 120 Bcf long and 130 Bcf short of futures, swaps
and options. As of December 31, 1996, the Company held a notional quantity of
approximately 185,000 MGal of NGL futures, swaps and options extending from
January 1997 to December 1997 with an average portfolio life of approximately
five months. This was comprised of approximately 55,000 MGal long and 130,000
MGal short of futures, swaps and options. In addition, as of December 31,
1996, the Company held approximately 99,000 MWh of electricity futures, swaps
and options all of which expired in January 1997. This was comprised of 44,000
MWh long and 55,000 MWh short with an average portfolio life of one month. 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 with an average portfolio life of approximately four months. This
was comprised of approximately 163 Bcf long and 167 Bcf short of futures, swaps
and options. As of December 31, 1995, the Company had no futures, swaps or
options positions outstanding related to NGLs or electricity.
The Company has hedged a portion of its equity volumes of residue gas and NGLs
in 1997, particularly in the first quarter, at pricing levels in excess of its
1997 operating budget. The Company's hedging strategy establishes a minimum and
maximum price to the Company while allowing market participation between these
levels. As of March 3, 1997, the Company had hedged approximately 60% of its
equity gas for 1997 at a weighted average NYMEX-equivalent minimum price of
$2.35 per Mcf, including approximately 70% of first quarter equity volumes at a
weighted average NYMEX-equivalent minimum price of $3.00 per Mcf. Additionally,
the Company has hedged approximately 50% of its equity NGLs for 1997 at a
weighted average composite Mont Belvieu and West Texas Intermediate Crude-
equivalent minimum price of $.40 per gallon, including approximately 70% of
first quarter equity volumes at a weighted average composite Mont Belvieu and
West Texas Intermediate Crude-equivalent minimum price of $.47 per gallon.
At December 31, 1996, the Company had $2.7 million of losses deferred in
inventory that will be recognized primarily during the first quarter of 1997 and
are expected to be offset by margins from the Company's related forward fixed
price hedges and physical
18
sales. At December 31, 1996, the Company had unrecognized net losses of $11.5
million related to financial instruments that are expected to be offset by
corresponding unrecognized net gains from the Company's obligations to sell
physical quantities of natural gas, NGLs and electric power.
During 1996, the Company began to enter into physical residue gas transactions
payable in Canadian Dollars. In order to insulate the Company from adverse
changes in currency exchange rates between the United States Dollar and the
Canadian Dollar, it has entered into foreign currency hedging transactions. As
of December 31, 1996, the notional value of such contracts was immaterial and
there were no gains or losses associated with such transactions for the year
ended December 31, 1996.
The Company enters into speculative futures, swap and option trades on a very
limited basis for purposes that include testing of hedging techniques. The
Company's procedures contain strict guidelines for such trading including
predetermined stop-loss requirements and net open positions limits. Speculative
futures, swap and option positions are marked to market at the end of each
accounting period and any gain or loss is recognized in income for that period.
Net gains from such speculative activities for the years ended December 31, 1996
and 1995 were not material.
Capital Investment Program
For the years ended December 31, 1996, 1995 and 1994 the Company expended $74.6
million, $78.5 million and $100.5 million, respectively, on new projects and
acquisitions. Capital expenditures related to existing operations are expected
to be approximately $154.4 million during 1997, consisting of the following:
capital expenditures related to gathering, processing and pipeline assets are
expected to be $112.8 million, of which $99.9 million will be used for new
connects, system expansions and asset consolidations and $12.9 million for
maintaining existing facilities. The Company expects capital expenditures on
exploration and production activities, the Katy Facility and miscellaneous items
to be $36.4 million, $3.3 million and $1.9 million, respectively. The Company's
1997 capital budget contemplates expenditures for two significant projects. See
further discussion in "Business and Properties - Significant Acquisitions and
Projects."
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,
none of which was outstanding at December 31, 1996. The facility's commitment
period is currently scheduled to terminate on April 1, 1998. If the facility is
not renewed, any outstanding balance thereunder at such time will convert to a
three-year term loan, which will be payable in 10 equal quarterly installments,
commencing July 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, 1996, the spread was .875% over the Eurodollar rate, resulting in
an interest rate of 6.5%. 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, 1996, the Company's debt to capitalization ratio was .45 to 1
resulting in a commitment fee rate of .30%. The Company is currently negotiating
with its bank syndicate for a new revolving credit facility. The new agreement
is expected to be in place within the second quarter of 1997.
Term Loan Facility. The Company also has a Term Loan Facility with four
banks with aggregate principal outstanding as of December 31, 1996 of $12.5
million bearing interest at 9.87%. The final payment on the Term Loan
Facility of $12.5 million is due in September 1997 and the Company intends to
finance this payment with amounts available under the Revolving Credit
Facility.
The agreements governing the Company's Revolving Credit and Term Loan Facilities
(the "Credit Facilities Agreements") contain certain mandatory prepayment terms.
If funded debt (as defined in the agreement) 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, 1996, taking into
account all the covenants contained in the Credit Facilities Agreement and
expected maturities of long-term debt during 1997, the Company had approximately
$240 million of available borrowing capacity.
The Credit Facilities Agreements are unsecured. Pursuant to the Credit
Facilities Agreements, the Company is required to maintain a current ratio (as
defined therein) of at least 1.0 to 1.0, a minimum tangible net worth equal to
the sum of $345 million plus 50% of consolidated net income earned after June
30, 1995 plus 75% of the net proceeds received after June 30, 1995 from the sale
of any equity securities, a debt to capitalization ratio (as defined therein) of
no more than 60% through December 31, 1996 and 55%
19
thereafter, and an EBITDA (as defined therein) 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 any capital stock 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 quarter of
1995 and paid in 1996 were excluded, per the agreement, from this calculation.
At December 31, 1996, $56.2 million was available under this limitation, which
is sufficient to pay required preferred stock dividends in 1997. 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. Net proceeds from the November 1996 offering of 6,325,000 shares of
Common Stock were used to reduce indebtedness under the Revolving Credit
Facility. At December 31, 1996, the Company had a cash balance of $39.5 million.
This cash balance is considered temporary as the cash will be used as the
Company commences its 1997 capital expenditure program.
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 Credit Facilities Agreements, 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 further restated and amended, is fully utilized,
as indicated in the following table (000s) :
Interest Final
Issue Date Amount Rate Maturity Principal Payments Due
- ------------------ ------ ----- ------------------ -----------------------------------------------
October 27, 1992 $ 25,000 7.51% October 27, 2000 $8,333 on each of October 27, 1998 through 2000
October 27, 1992 25,000 7.99% October 27, 2003 $8,333 on each of October 27, 2001 through 2003
September 22, 1993 25,000 6.77% September 22, 2003 single payment at maturity
December 27, 1993 25,000 7.23% December 27, 2003 single payment at maturity
October 27, 1994 25,000 9.05% October 27, 2001 single payment at maturity
October 27, 1994 25,000 9.24% October 27, 2004 single payment at maturity
July 28, 1995 50,000 7.61% July 28, 2007 $10,000 on each of July 28, 2003 through 2007
--------
$200,000
========
1993 Senior Notes. On April 28, 1993, the Company sold $50 million of
7.65% Senior Notes ("1993 Senior Notes") due 2003 to a group of insurance
companies. Annual principal payments of $7.1 million on the 1993 Senior Notes
are due on April 30 of each year from 1997 through 2002, with any remaining
principal and interest outstanding due on April 30, 2003. The Company intends
to finance the $7.1 million payment due in 1997 with amounts available under
the Revolving Credit Facility. 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.
Receivables Facility. In April 1995, the Company entered into an agreement
with Receivables Capital Corporation ("RCC"), as purchaser, and Bank of America
National Trust and Savings Association, as agent, pursuant to which the Company
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 5.8421% as of December 31, 1996. The Receivables Facility has a
364-day term and contains financial covenants similar to those in the Credit
Facilities Agreements, as restated and amended, along with certain covenants
regarding the quality of the trade receivables pool. The parties have renewed
the facility through May 29, 1997. The Company anticipates that it will renew
the facility with the current purchaser, enter into a similar agreement with a
new purchaser or repay the facility with amounts available under the Revolving
Credit Facility.
20
Covenant Compliance. At December 31, 1996, 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 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, 1996 and 1995, there were no such outstanding interest rate swap
agreements. In addition to the financial risk, which will vary during the life
of 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 interest 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.
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 waste
management. The Company employs seven 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 operations.
The Company anticipates that it is reasonably likely that the trend in
environmental legislation and regulation will continue to be towards stricter
standards. The Company is unaware of future environmental standards that are
reasonably likely to be adopted that will have a material effect on the
Company's financial position or results of operations, but it cannot rule out
that possibility.
The Company is in the process of voluntarily cleaning up substances at
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
significant in relation to the results of operations of the Company and totaled
approximately $1.3 million for the year ended December 31, 1996, including
approximately $888,000 in air emissions fees paid to the states in which it
operates. Although the Company anticipates that such environmental expenses will
increase over time, the Company does not believe that such increases will have a
material effect on the Company's financial position or results of operations.
Business Strategy
The Company's three-part business plan is designed to increase profitability
through (i) investing in projects that complement and expand its core gas
gathering, processing and marketing business; (ii) expanding its energy
marketing services and sales volumes; and (iii) continuing to optimize the
profitability of existing operations.
Expansion of Core Business
The Company continually evaluates investments in projects that meet its
objectives of complementing existing operations, expanding into new areas or
providing enhanced marketing opportunities. These projects typically include gas
gathering, treating, processing, transportation or storage assets, NGL product
upgrade equipment or peaking power generation facilities. See further
discussion in "Business and Properties - Significant Acquisitions and Projects."
21
Expand Energy Marketing Services and Volumes
Prior to deregulation of the natural gas industry, the Company's marketing
activities were directed towards selling residue gas and NGLs processed at its
plants to ensure their efficient operation. As the natural gas industry
deregulated and new market opportunities developed, the Company began to
increase its third-party marketing. In order to compete in today's energy
marketplace, a marketer must provide a full range of services and products to
meet its customers' demands. The Company is a full-service marketer of residue
gas and NGL products and has now expanded into the sale of electric power. The
Company focuses on the individual needs of its customers and is committed to
developing products and services that are tailored to meet their requirements.
The Company plans to expand its energy marketing activities by: (i) pursuing
higher-margin, end-use markets; (ii) increasing third-party gas, NGL and
electric power sales volumes; and (iii) engaging in retail electric power sales
as those markets become available through deregulation. The Company believes it
competes effectively with other marketers due to its national marketing presence
and the marketing information gained thereby, the services it provides and its
physical asset base.
Optimize Profitability
The Company seeks to optimize the profitability of its operations by: (i)
maintaining or increasing natural gas throughput levels; (ii) increasing its
efficiency through the consolidation of existing facilities; (iii) investing in
assets that enhance product value; (iv) selling non-strategic assets; and (v)
controlling operating and overhead expenses. In order to maximize its
competitive advantages, the Company continually monitors the economic
performance of each of its operating facilities to ensure that a desired cash
flow objective and operating efficiency is achieved.
22
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements
Western Gas Resources, Inc.'s Consolidated Financial Statements as of December
31, 1996 and 1995 and for each of the three years in the period ended December
31, 1996:
Page
----
Report of Management......................................... 24
Report of Independent Accountants............................ 25
Consolidated Balance Sheets.................................. 26
Consolidated Statements of Cash Flows........................ 27
Consolidated Statements of Operations........................ 28
Consolidated Statements of Changes in Stockholders' Equity... 29
Notes to Consolidated Financial Statements................... 30
23
REPORT OF MANAGEMENT
The financial statements and other financial information included in this Annual
Report on Form 10-K are the responsibility of Management. The financial
statements have been prepared in conformity with generally accepted accounting
principles appropriate in the circumstances and include amounts that are based
on Management's informed judgments and estimates.
Management relies on the Company's system of internal accounting controls to
provide reasonable assurance that assets are safeguarded and that transactions
are properly recorded and executed in accordance with Management's
authorization. The concept of reasonable assurance is based on the recognition
that there are inherent limitations in all systems of internal accounting
control and that the cost of such systems should not exceed the benefits to be
derived. The internal accounting controls, including internal audit, in place
during the periods presented are considered adequate to provide such assurance.
The Company's financial statements are audited by Price Waterhouse LLP,
independent accountants. Their report states that they have conducted their
audit in accordance with generally accepted auditing standards. These standards
include an evaluation of the system of internal accounting controls for the
purpose of establishing the scope of audit testing necessary to allow them to
render an independent professional opinion on the fairness of the Company's
financial statements.
Oversight of Management's financial reporting and internal accounting control
responsibilities is exercised by the Board of Directors, through an Audit
Committee that consists solely of outside directors. The Audit Committee meets
periodically with financial management, internal auditors and the independent
accountants to review how each is carrying out its responsibilities and to
discuss matters concerning auditing, internal accounting control and financial
reporting. The independent accountants and the Company's internal audit
department have free access to meet with the Audit Committee without Management
present.
Signature Title
- --------- -----
/S/ L. F. Outlaw
- ----------------
L. F. Outlaw President and Chief Operating Officer
/S/ William J. Krysiak
- ----------------------
William J. Krysiak Vice President - Finance (Principal Financial and
Accounting Officer)
24
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,
1996 and 1995, and the results of their cash flows and their operations for each
of the three years in the period ended December 31, 1996, in conformity with
generally accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
As discussed in Note 2 to the financial statements, the Company changed its
method of accounting for the impairment of long-lived assets in 1995 to comply
with the provisions of Statement of Financial Accounting Standards No. 121.
PRICE WATERHOUSE LLP
Denver, Colorado
March 7, 1997
25
WESTERN GAS RESOURCES, INC.
CONSOLIDATED BALANCE SHEET
(000s)
December 31,
------------------------
ASSETS 1996 1995
------ ---- ----
Current assets:
Cash and cash equivalents................................................... $ 39,504 $ 5,795
Trade accounts receivable, net.............................................. 338,708 204,426
Product inventory........................................................... 25,972 28,154
Parts inventory............................................................. 2,599 2,427
Other....................................................................... 1,477 1,524
---------- ----------
Total current assets..................................................... 408,260 242,326
---------- ----------
Property and equipment:
Gas gathering, processing, storage and transmission......................... 938,902 882,801
Oil and gas properties and equipment........................................ 144,732 140,691
Construction in progress.................................................... 35,250 26,314
---------- ----------
1,118,884 1,049,806
Less: Accumulated depreciation, depletion and amortization.................. (252,571) (200,203)
---------- ----------
Total property and equipment, net...................................... 866,313 849,603
---------- ----------
Other assets:
Gas purchase contracts (net of accumulated amortization of $24,552 and
$19,273, respectively)................................................. 46,689 54,637
Other....................................................................... 40,369 47,431
---------- ----------
Total other assets..................................................... 87,058 102,068
---------- ----------
Total assets................................................................... $1,361,631 $1,193,997
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
Current liabilities:
Accounts payable............................................................ $ 386,268 $ 199,513
Accrued expenses............................................................ 28,670 19,204
Dividends payable........................................................... 4,215 3,898
---------- ----------
Total current liabilities.............................................. 419,153 222,615
Long-term debt................................................................. 379,500 529,500
Deferred income taxes payable.................................................. 82,511 69,973
---------- ----------
Total liabilities...................................................... 881,164 822,088
---------- ----------
Commitments and contingent liabilities......................................... - -
Stockholders' equity:
Preferred Stock; 10,000,000 shares authorized:
$2.28 cumulative preferred stock, par value $.10; 1,400,000 shares issued
($35,000 aggregate liquidation preference).......................... 140 140
$2.625 cumulative convertible preferred stock, par value $.10; 2,760,000
issued ($138,000 aggregate liquidation preference).................. 276 276
Common stock, par value $.10; 100,000,000 shares authorized; 32,134,151 and
25,794,728 shares issued, respectively................................. 3,213 2,580
Treasury stock, at cost; 25,016 shares in treasury.......................... (788) (788)
Additional paid-in capital.................................................. 397,061 301,234
Retained earnings........................................................... 82,378 70,348
Notes receivable from key employees secured by common stock................. (1,813) (1,881)
---------- ----------
Total stockholders' equity............................................. 480,467 371,909
---------- ----------
Total liabilities and stockholders' equity..................................... $1,361,631 $1,193,997
========== ==========
The accompanying notes are an integral part of the consolidated financial
statements.
26
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(000s)
Year Ended December 31,
--------------------------------------
1996 1995 1994
------------ ---------- ----------
Reconciliation of net income to net cash provided by operating activities:
Net income (loss)............................................................. $ 27,941 $ (6,108) $ 7,364
Add income items that do not affect cash:
Depreciation, depletion and amortization.................................... 63,207 65,361 63,586
Deferred income taxes....................................................... 12,538 1,246 2,246
Distributions in excess of equity income, net............................... 4,339 - -
Gain on the sale of property and equipment.................................. (2,747) (939) -
Loss on the impairment of long-lived assets................................. - 17,642 -
Other non-cash items, net................................................... 336 (1,360) 452
----------- --------- ---------
105,614 75,842 73,648
----------- --------- ---------
Adjustments to working capital to arrive at net cash provided by
operating activities:
(Increase) decrease in trade accounts receivable............................ (134,538) (69,982) 7,892
(Increase) decrease in product inventory.................................... 2,115 22,985 (30,289)
Increase in parts inventory................................................. (172) (136) (130)
(Increase) decrease in other current assets................................. (42) (157) 177
Increase in other assets and liabilities, net............................... (733) (391) (241)
Increase (decrease) in accounts payable..................................... 186,758 54,269 (15,712)
Increase (decrease) in accrued expenses..................................... 9,264 4,786 (4,322)
Increase (decrease) in income taxes payable................................. - (843) 843
----------- --------- ---------
Total adjustments........................................................ 62,652 10,531 (41,782)
----------- --------- ---------
Net cash provided by operating activities.................................... 168,266 86,373 31,866
----------- --------- ---------
Cash flows from investing activities:
Purchases of property and equipment, including acquisitions................. (74,203) (56,138) (91,833)
Proceeds from the disposition of property and equipment..................... 7,656 13,328 10,897
Distribution from unconsolidated affiliates................................. 1,500 - -
Contributions to unconsolidated affiliates.................................. (352) (4,237) (1,189)
Gas purchase contracts acquired............................................. - (18,146) (7,518)
----------- --------- ---------
Net cash used in investing activities........................................ (65,399) (65,193) (89,643)
----------- --------- ---------
Cash flows from financing activities:
Net proceeds from issuance of common stock.................................. 96,376 - -
Net proceeds from exercise of common stock options.......................... 62 117 413
Proceeds from issuance of long-term debt.................................... - 92,000 125,000
Payments on long-term debt.................................................. (12,500) (25,000) -
Borrowings under revolving credit facility.................................. 1,035,377 625,400 347,400
Payments on revolving credit facility....................................... (1,172,877) (655,900) (526,400)
Debt issue costs paid....................................................... - (1,884) (827)
Dividends paid.............................................................. (15,596) (16,796) (16,443)
Redemption of preferred stock............................................... - (42,030) -
Net proceeds from issuance of preferred stock............................... - - 132,676
----------- --------- ---------
Net cash (used in) provided by financing activities........................... (69,158) (24,093) 61,819
----------- --------- ---------
Net increase (decrease) in cash............................................... 33,709 (2,913) 4,042
Cash and cash equivalents at beginning of period.............................. 5,795 8,708 4,666
----------- --------- ---------
Cash and cash equivalents at end of period.................................... $ 39,504 $ 5,795 $ 8,708
=========== ========= =========
The accompanying notes are an integral part of the consolidated financial
statements.
27
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
(000s, except share and per share amounts)
Year Ended December 31,
-----------------------------------------
1996 1995 1994
---- ---- ----
Revenues:
Sale of residue gas................................ $ 1,440,882 $ 876,399 $ 707,869
Sale of natural gas liquids........................ 561,581 331,760 309,358
Processing, transportation and storage revenue..... 44,943 41,358 35,057
Sale of electric power............................. 30,667 - -
Other, net......................................... 12,936 7,467 11,205
----------- ----------- -----------
Total revenues.................................. 2,091,009 1,256,984 1,063,489
----------- ----------- -----------
Costs and expenses:
Product purchases.................................. 1,844,151 1,040,265 853,398
Plant operating expense............................ 73,116 71,030 68,500
Oil and gas exploration and production costs....... 5,056 5,117 5,449
Selling and administrative expense................. 29,411 26,610 29,598
Depreciation, depletion and amortization........... 63,207 65,361 63,586
Interest expense................................... 34,437 37,160 31,434
Restructuring charge............................... - 2,065 -
Loss on the impairment of long-lived assets........ - 17,642 -
----------- ----------- -----------
Total costs and expenses........................ 2,049,378 1,265,250 1,051,965
----------- ----------- -----------
Income (loss) before income taxes..................... 41,631 (8,266) 11,524
Provision (benefit) for income taxes:
Current............................................ 1,152 (3,404) 1,913
Deferred........................................... 12,538 1,246 2,247
----------- ----------- -----------
Total provision (benefit) for income taxes...... 13,690 (2,158) 4,160
----------- ----------- -----------
Net income (loss)..................................... 27,941 (6,108) 7,364
Preferred stock requirements.......................... (10,439) (15,431) (12,212)
----------- ----------- -----------
Income (loss) attributable to common stock............ $ 17,502 $ (21,539) $ (4,848)
=========== =========== ===========
Earnings (loss) per share of common stock............. $ .66 $ (.84) $ (.19)
=========== =========== ===========
Weighted average shares of common stock outstanding... 26,519,635 25,753,738 25,695,760
=========== =========== ===========
The accompanying notes are an integral part of the consolidated financial
statements.
28
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 Shares Senior
Perpetual $2.28 Cumulative of Common Perpetual $2.28
Convertible Cumulative Convertible Shares Stock Convertible Cumulative
Preferred Preferred Preferred of Common in Preferred Preferred
Stock Stock Stock Stock Treasury Stock 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 perpetual
convertible preferred stock (400,000) - - - - (40) -
Dividends declared on common
stock....................... - - - - - - -
Dividends declared on 7.25%
cumulative senior perpetual
convertible preferred stock - - - - - - -
Dividends declared on $2.28
cumulative preferred stock.. - - - - - - -
Dividends declared on $2.625
cumulative convertible
preferred stock............ - - - - - - -
----------- ---------- ---------- ----------- --------- ---------- -----------
Balance at December 31, 1995. - 1,400,000 2,760,000 25,769,712 25,016 - 140
Net income, 1996............. - - - - - - -
Stock options exercised...... - - - 14,423 - - -
Loans forgiven............... - - - - - - -
Common stock offering........ - - - 6,325,000 - - -
Dividends declared on common
stock....................... - - - - - - -
Dividends declared on $2.28
cumulative preferred stock.. - - - - - - -
Dividends declared on $2.625
cumulative convertible
preferred stock............ - - - - - - -
----------- ---------- ---------- ----------- --------- ---------- -----------
Balance at December 31, 1996. - 1,400,000 2,760,000 32,109,135 25,016 $ - $140
=========== ========== ========== =========== ========= ========== ===========
$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, 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
Net income, 1996............. - - - - 27,941 - 27,941
Stock options exercised...... - 1 - 83 - (24) 60
Loans forgiven............... - - - - - 92 92
Common stock offering........ - 632 - 95,744 - - 96,376
Dividends declared on common
stock....................... - - - - (5,472) - (5,472)
Dividends declared on $2.28
cumulative preferred stock.. - - - - (3,194) - (3,194)
Dividends declared on $2.625
cumulative convertible
preferred stock........... - - - - (7,245) - (7,245)
---------- ------ ------ -------- -------- ------- --------
Balance at December 31, 1996. $276 $3,213 $(788) $397,061 $ 82,378 $(1,813) $480,467
========== ====== ====== ======== ======== ======= ========
The accompanying notes are an integral part of the consolidated financial
statements.
29
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - NATURE OF ORGANIZATION
- -------------------------------
Western Gas Resources, Inc. (the "Company"), a Delaware corporation, is an
independent gas gatherer and processor and energy marketer providing a full
range of services to its customers from the wellhead to the delivery point. The
Company designs, constructs, owns and operates natural gas gathering,
processing, treating and storage facilities in major gas-producing basins in the
Rocky Mountain, Mid-Continent, Gulf Coast and Southwestern regions of the United
States. The Company connects producers' wells to its gathering systems for
delivery to its processing or treating plants, processes the natural gas to
extract natural gas liquids ("NGLs") and treats the natural gas in order to meet
pipeline specifications. The Company markets natural gas, NGLs and electric
power nationwide, providing risk management, storage, transportation,
scheduling, peaking and other services to a variety of customers. The Company
also owns certain producing properties, primarily in Louisiana, Texas and
Wyoming.
Western Gas Resources, Inc. was formed in October 1989 to acquire a majority
interest in Western Gas Processors, Ltd. (the "Partnership") and to assume the
duties of WGP Company, the general partner of the Partnership. The Partnership
was a Colorado limited partnership formed in 1977 to engage in the gathering and
processing of natural gas. The reorganization was accomplished in December 1989
through an exchange for common stock of partnership units held by the former
general partners of WGP Company and an initial public offering of Western Gas
Resources, Inc.'s Common Stock. On May 1, 1991, a further restructuring
("Restructuring") of the Partnership and Western Gas Resources, Inc. (together
with its predecessor, WGP Company, collectively, the "Company") was approved by
a vote of the security holders. The combinations were reorganizations of
entities under common control and were accounted for at historical cost in a
manner similar to poolings of interests.
The Company has completed three public offerings of Common Stock. In December
1989, the Company issued 3,527,500 shares of Common Stock at a public offering
price of $11.50. In November 1991, the Company issued 4,115,000 shares of Common
Stock at a public offering price of $18.375 per share. In November 1996, the
Company issued 6,325,000 shares of Common Stock at a public offering price of
$16.25 per share. The net proceeds to the Company from the November 1996 public
offering of $96.4 million were primarily used to reduce indebtedness under the
Revolving Credit Facility.
The Company has also issued preferred stock in a private transaction and has
completed two public offerings of preferred stock. In October 1991, the Company
issued 400,000 shares of 7.25% Cumulative Senior Perpetual Convertible Preferred
Stock ("7.25% Preferred Stock") with a liquidation preference of $100 per share
to an institutional investor. In May 1995, the Company redeemed all of the
issued and outstanding shares of its 7.25% Preferred Stock pursuant to the
provisions of its Certificate of Designation relating to such preferred stock,
at an aggregate redemption price of approximately $42.0 million, including a
redemption premium of $2.0 million. In November 1992, the Company issued
1,400,000 shares of $2.28 Cumulative Preferred Stock with a liquidation
preference of $25 per share, at a public offering price of $25 per share,
redeemable at the Company's option on or after November 15, 1997. In February
1994, the Company issued 2,760,000 shares of $2.625 Cumulative Convertible
Preferred Stock with a liquidation preference of $50 per share, at a public
offering price of $50 per share, redeemable at the Company's option on or after
February 16, 1997.
Significant Business Acquisitions, Dispositions and Projects
Bethel Facility (Cotton Valley Pinnacle Reef)
The Company is currently constructing the Bethel facility in East Texas that
will gather gas from the Cotton Valley Pinnacle Reef trend. The Bethel facility
has been designed to accommodate incremental expansions, depending upon the
success of continued development in the trend. Construction of the Bethel
facility began in September 1996. During the year ended December 31, 1996, the
Company has expended approximately $10.1 million for such facility.
Coal Seam Gathering System Expansion
The Company plans to expand its Powder River Basin coal seam natural gas
gathering system and develop its own coal seam gas reserves in Wyoming. The
Company has acquired drilling rights in the vicinity of known coal seam
production. The Company will utilize its existing dry gas gathering system and
interstate pipeline to transport this pipeline quality gas to market. During
the year ended December 31, 1996, the Company has expended approximately $6.9
million on this project. In March 1997, the Company purchased certain operating
wells and undeveloped acreage of a producer in the Powder River Basin for $12.4
million in cash and an additional payment of approximately $7.9 million payable
in January 1998.
30
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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., 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 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 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 an agreement with Oasis for
100 MMcf per day of firm transportation service on its intrastate pipeline
through December 1999. The Company has installed a 200 MMcf per day pipeline
interconnection between this pipeline and the Katy Hub and Gas Storage Facility
("Katy Facility"). During 1996, the Company sold the remaining portion of the
Crockett facility for $760,000, which resulted in an immaterial pre-tax gain.
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.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- ---------------------------------------------------
The significant accounting policies followed by the Company and its wholly owned
subsidiaries are presented here to assist the reader in evaluating the financial
information contained herein. The Company's accounting policies are in
accordance with generally accepted accounting principles.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company and
the Company's wholly owned subsidiaries. All material 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 residue gas, NGLs
or electric power 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 income (loss)
attributable to common stock by the weighted average shares of common stock
outstanding. Income (loss) attributable to common stock is income (loss) less
preferred stock dividends. The Company declared preferred stock dividends of
$10.4 million, $11.6 million and $12.2 million for the years ended December 31,
1996, 1995 and 1994, respectively. For the year ended December 31, 1995, income
(loss) attributable to common stock was also reduced by a $2.0 million
redemption premium and certain up-front costs of $1.8 million paid on the 7.25%
Preferred Stock. The computation of fully diluted earnings per share of common
stock for each of the three years in the period ended December 31, 1996 was not
dilutive; therefore, only primary earnings per share of common stock is
presented.
31
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Inventories
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. Product inventory includes $19.3 million
and $23.3 million of residue gas and $6.7 million and $4.8 million of NGLs at
December 31, 1996 and 1995, respectively.
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.
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 gas purchase contracts is amortized using
the straight-line method.
Oil and Gas Properties and Equipment
The Company follows the successful efforts method of accounting for oil and gas
exploration and production activities. Acquisition costs, development costs and
successful exploration costs are capitalized. Exploratory dry hole costs, lease
rentals and geological and geophysical costs are charged to expense as incurred.
Upon surrender of undeveloped properties, the original cost is charged against
income. Producing properties and related equipment are depleted and depreciated
by the units-of-production method based on estimated proved reserves for
producing properties and proved developed reserves for lease and well equipment.
Impairment of Long-Lived Assets
On 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" ("SFAS No. 121"), 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 cash flows discounted 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."
Residue Gas, NGL and Electric Power Hedges
Gains and losses on hedges of product inventory are included in the carrying
amount of the inventory and are ultimately recognized in 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, NGL and
electric power sales when the hedged physical transaction occurs. For purposes
of the Consolidated Statement of Cash Flows, all hedging transactions are
classified in net cash provided by operating activities.
32
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 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 and over-the-
counter ("OTC") swaps and options. The risk is limited due to the large number
of entities comprising the Company's customer base and their dispersion across
industries and geographic locations. At December 31, 1996, the Company believes
it had no significant concentrations of credit risk.
Cash and Cash Equivalents
Cash and cash equivalents includes all cash balances and highly liquid
investments with an original maturity of three months or less.
Supplementary Cash Flow Information
Interest paid was $36.7 million, $38.8 million and $32.8 million, respectively,
for the years ended December 31, 1996, 1995 and 1994. Capitalized interest
associated with construction of new projects was $1.7 million, $1.5 million and
$1.5 million, respectively, for the years ended December 31, 1996, 1995 and
1994.
Income taxes paid were $4.2 million, $1.6 million and $1.1 million,
respectively, for the years ended December 31, 1996, 1995 and 1994.
In February 1994, the then-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.
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 residue 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
33
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUNED)
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.
Stock Compensation
In October 1995, the Financial Accounting Standards Board issued SFAS No. 123,
"Accounting for Stock-Based Compensation" ("SFAS No. 123"), 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"
("APB No. 25 ") The Company has complied with the pro forma disclosure
requirements of SFAS No. 123 as required under the pronouncement.
Reclassifications
Certain prior years' amounts in the consolidated financial statements and
related notes have been reclassified to conform to the presentation used in
1996.
NOTE 3 - RELATED PARTIES
- ------------------------
The Company enters into joint ventures in order to diversify risk, create
strategic alliances and to establish itself in oil and gas producing basins in
the United States. For the years ended December 31, 1996, 1995 and 1994, the
Company had a 50% ownership interest in the Williston Gas Company ("Williston")
and Westana Gathering Company ("Westana") and also acts as operator. The Company
entered into Redman Smackover in 1995. In addition, the Company entered into the
Sandia Energy Resources Joint Venture ("Sandia") in March 1996. The Company has
a 49% interest and also provides various administrative services to Sandia. The
Company's share of equity income or loss in these ventures is reflected in Other
net revenue. All transactions entered into by the Company with its related
parties are consummated in the ordinary course of business.
Historically, the Company had purchased a significant portion of the production
of Williston. The Company also performed various operational and administrative
functions for Williston and charged a monthly overhead fee to cover such
services. In August 1996, substantially all of the assets associated with
Williston were sold to a third party. The Company expects that Williston will
be dissolved during 1997 at which time all inter-company balances will be
settled and the remaining assets of Williston will be salvaged. At December 31,
1996, the Company's investment in Williston was $348,000.
The Company performs various operational and administrative functions for
Westana and charges a monthly overhead fee to cover such services. The Company
records receivable and payable balances at the end of each accounting period
related to transactions with Westana and Redman Smackover. At December 31, 1996,
the Company's investments in Westana and Redman Smackover was $24.5 million and
$5.4 million, respectively.
The Company provides substantially all of the natural gas that Sandia markets.
In addition, the Company purchases residue gas from Sandia. The Company records
receivable and payable balances at the end of each accounting period related to
the above referenced transactions. At December 31, 1996, the Company's
investment in Sandia was $141,000.
34
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following table summarizes account balances reflected in the financial
statements (000s):
As of or for the Year Ended December 31,
----------------------------------------
1996 1995 1994
------------ ----------- -----------
Accounts Receivable.................... $ 5,552 $ 1,549 $1,676
======= ======= =======
Accounts Payable....................... 11,041 4,979 3,033
======= ======= =======
Sales.................................. 10,592 - -
======= ======= =======
Purchases.............................. 57,675 28,196 24,475
======= ======= =======
Administrative Costs................... $ 419 $ 665 $ 891
======= ======= =======
In February 1994, the then-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.
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 9). The Company will forgive the
loan and accrued interest if the employee has been continuously employed by the
Company for periods specified under the agreements and Board of Directors'
resolutions. As of December 31, 1996 and 1995, loans, including accrued
interest, totaling $2.2 million and $2.1 million, respectively, were outstanding
to certain employees under these programs. The loans are secured by a portion of
the Common Stock issued upon exercise of the options and are accounted for as a
reduction of stockholders' equity. During 1996 and 1995, the Board of Directors
approved the forgiveness of loans and accrued interest to key employees totaling
approximately $103,000 and $59,000, respectively, after resignation and prior to
satisfaction of the continuous service requirements of the loan agreement.
NOTE 4 - RISK MANAGEMENT
- ------------------------
Residue Gas, NGL and Electric Power Hedges
The Company's commodity price risk management program has two primary
objectives. The first goal is to preserve and enhance the value of the
Company's equity volumes of residue gas and NGLs with regard to the impact of
commodity price movements on cash flow, net income and earnings per share in
relation to those anticipated by the Company's operating budget. The second goal
is to manage price risk related to the Company's physical residue gas, NGL and
power marketing activities to protect profit margins. This risk relates to
hedging fixed price purchase and sale commitments, preserving the value of
storage inventories, reducing exposure to physical market price volatility and
providing risk management services to a variety of customers.
The Company utilizes a combination of fixed price forward contracts, exchange-
traded futures and options, as well as fixed index swaps, basis swaps and
options traded in the OTC market. These instruments allow the Company to
preserve value and protect margins because gains or losses in the physical
market are offset by corresponding losses or gains in the value of the financial
instruments.
The Company uses futures, swaps and options to reduce price risk and basis
risk. Basis is the difference in price between the physical commodity being
hedged and the price of the futures contract used for hedging. Basis risk is
the risk that an adverse change in the futures market will not be completely
offset by an equal and opposite change in the cash price of the commodity being
hedged. Basis risk exists in natural gas primarily due to the geographic price
differentials between cash market locations and futures contract delivery
locations.
35
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The Company enters into futures transactions on the New York Mercantile Exchange
("NYMEX") and the Kansas City Board of Trade and through OTC swaps and options
with creditworthy counterparties consisting primarily of financial institutions
and other natural gas companies. The Company conducts its standard credit
review of OTC counterparties and has agreements with such parties that contain
collateral requirements. The Company generally uses standardized swap
agreements that allow for offset of positive and negative exposures. OTC
exposure is marked to market daily for the credit review process. The Company's
OTC credit risk exposure is partially limited by its ability to require a margin
deposit based upon the mark-to-market value of the counterparties' net exposure.
The Company is subject to margin deposit requirements under these same
agreements. In addition, the Company is subject to similar margin deposit
requirements for its NYMEX counterparties related to its net exposures.
The use of financial instruments may expose the Company to the risk of financial
loss in certain circumstances, including instances when (i) equity volumes are
less than expected, (ii) the Company's customers fail to purchase or deliver the
contracted quantities of natural gas or NGLs, or (iii) the Company's OTC
counterparties fail to perform. To the extent that the Company engages in
hedging activities, it may be prevented from realizing the benefits of favorable
price changes in the physical market. However, it is similarly insulated
against decreases in such prices.
As of December 31, 1996, the Company held a notional quantity of approximately
250 Bcf of natural gas futures, swaps and options extending from January 1997 to
October 1998 with an average portfolio life of approximately four months. This
was comprised of approximately 120 Bcf long and 130 Bcf short of futures, swaps
and options. As of December 31, 1996, the Company held a notional quantity of
approximately 185,000 MGal of NGL futures, swaps and options extending from
January 1997 to December 1997 with an average portfolio life of approximately
five months. This was comprised of approximately 55,000 MGal long and 130,000
MGal short of futures, swaps and options. In addition, as of December 31,
1996, the Company held approximately 99,000 MWh of electricity futures, swaps
and options all of which expired in January 1997. This was comprised of 44,000
MWh long and 55,000 MWh short with an average portfolio life of one month. 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 with an average portfolio life of approximately four months. This
was comprised of approximately 163 Bcf long and 167 Bcf short of futures, swaps
and options. As of December 31, 1995, the Company had no futures, swaps or
options positions outstanding related to NGLs or electricity.
At December 31, 1996, the Company had $2.7 million of losses deferred in
inventory that will be recognized primarily during the first quarter of 1997 and
are expected to be offset by margins from the Company's related forward fixed
price hedges and physical sales. At December 31, 1996, the Company had
unrecognized net losses of $11.5 million related to financial instruments that
are expected to be offset by corresponding unrecognized net gains from the
Company's obligations to sell physical quantities of natural gas, NGLs and
electric power.
During 1996, the Company began to enter into physical residue gas transactions
payable in Canadian Dollars. In order to insulate the Company from adverse
changes in currency exchange rates between the United States Dollar and the
Canadian Dollar, it has entered into foreign currency hedging transactions. As
of December 31, 1996, the notional value of such contracts was immaterial and
there were no gains or losses associated with such transactions for the year
ended December 31, 1996.
The Company enters into speculative futures, swap and option trades on a very
limited basis for purposes that include testing of hedging techniques. The
Company's procedures contain strict guidelines for such trading including
predetermined stop-loss requirements and net open positions limits. Speculative
futures, swap and option positions are marked to market at the end of each
accounting period and any gain or loss is recognized in income for that period.
Net gains from such speculative activities for the years ended December 31, 1996
and 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 interest rate lock, interest rates had decreased, which resulted in the
realization of a $390,000 loss. The Company considered the loss to be
36
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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, 1996 and 1995,
there were no outstanding interest rate swap agreements.
NOTE 5 - FINANCIAL INSTRUMENTS
- ------------------------------
The estimated fair values of the Company's financial instruments have been
determined by the Company using available market information and valuation
methodologies. Considerable judgment is required to develop the estimates of
fair value; thus, the estimates provided herein are not necessarily indicative
of the amount that the Company could realize upon the sale or refinancing of
such financial instruments.
December 31, 1996 December 31, 1995
-------------------- -----------------------
Carrying Fair Carrying Fair
Value Value Value Value
-------- --------- ---------- ----------
(000s) (000s)
Cash and cash equivalents................... $ 39,504 $ 39,504 $ 5,795 $ 5,795
Trade accounts receivable................... 338,708 338,708 204,426 204,426
Accounts payable............................ 386,268 386,268 199,513 199,513
Long-term debt.............................. 379,500 376,076 529,500 528,176
Risk management contracts................... $ - $(11,460) $ - $(11,720)
The following methods and assumptions were used by the Company in estimating the
fair value of its financial instruments:
Cash and cash equivalents, trade accounts receivable and accounts payable
Due to the short-term nature of these instruments, the carrying value
approximates the fair value.
Long-term debt
The Company's long-term debt was primarily comprised of fixed rate facilities;
for this portion, fair market value was estimated using discounted cash flows
based upon the Company's current borrowing rates for debt with similar
maturities. The remaining portion of the long-term debt was borrowed on a
revolving basis that accrues interest at current rates; as a result, carrying
value approximates fair value of the outstanding debt.
Risk Management Contracts
Fair value represents the amount at which the instrument could be exchanged in a
current arms-length transaction.
NOTE 6 - DEBT
- -------------
The following summarizes the Company's consolidated debt at the dates indicated
(000s):
December 31,
-------------------
1996 1995
-------- --------
Master shelf and senior notes............. $292,000 $292,000
Receivables facility...................... 75,000 75,000
Bank term loan facility................... 12,500 25,000
Variable rate revolving credit facility... - 137,500
-------- --------
Total long-term debt..................... $379,500 $529,500
======== ========
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,
none of which was outstanding at December 31, 1996. The facility's
commitment period will terminate on April 1, 1998.
37
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
If the facility is not renewed, any outstanding balance thereunder at such time
will convert to a three-year term loan, which will be payable in 10 equal
quarterly installments, commencing July 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, 1996, the spread was .875% over the
Eurodollar rate, resulting in an interest rate of 6.5%. 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, 1996, the Company's debt to
capitalization ratio was .45 to 1 resulting in a commitment fee rate of .30%.
The Company is currently negotiating with its bank syndicate for a new revolving
credit facility. The new agreement is expected to be in place within the second
quarter of 1997.
Term Loan Facility. The Company also has a Term Loan Facility with four
banks with aggregate principal outstanding as of December 31, 1996 of $12.5
million bearing interest at 9.87%. The final payment on the Term Loan
Facility of $12.5 million is due in September 1997 and the Company intends to
finance this payment with amounts available under the Revolving Credit
Facility.
The agreements governing the Company's Revolving Credit and Term Loan Facilities
(the "Credit Facilities Agreements") contain certain mandatory prepayment terms.
If funded debt (as defined in the agreement) 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, 1996, taking into
account all the covenants contained in the Credit Facilities Agreements and
expected maturities of long-term debt during 1997, the Company had approximately
$240 million of available borrowing capacity.
The Credit Facilities Agreements are unsecured. Pursuant to the Credit
Facilities Agreements, the Company is required to maintain a current ratio (as
defined therein) of at least 1.0 to 1.0, a minimum tangible net worth equal to
the sum of $345 million plus 50% of consolidated net income earned after June
30, 1995 plus 75% of the net proceeds received after June 30, 1995 from the sale
of any equity securities, a debt to capitalization ratio (as defined therein) of
no more than 60% through December 31, 1996 and 55% thereafter, and an EBITDA (as
defined therein) 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
any capital stock 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 quarter of 1995 and paid in 1996 were excluded, per the
agreement, from this calculation. At December 31, 1996, $56.2 million was
available under this limitation, which is sufficient to pay required preferred
stock dividends in 1997. 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. Net proceeds from the November 1996
offering of 6,325,000 shares of Common Stock were used to reduce indebtedness
under the Revolving Credit Facility. At December 31, 1996, the Company had a
cash balance of $39.5 million. The cash balance is considered temporary as the
cash will be used as the Company commences its 1997 capital expenditure program.
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 Credit Facilities Agreements, 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)
38
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
and to extend the term of the Master Shelf to October 31, 1995. The Master Shelf
Agreement, as further restated and amended, is fully utilized, as indicated in
the following table (000s):
Interest Final
Issue Date Amount Rate Maturity Principal Payments Due
- ------------------ ------ ---- ------------------ -----------------------------------------------
October 27, 1992 $ 25,000 7.51% October 27, 2000 $8,333 on each of October 27, 1998 through 2000
October 27, 1992 25,000 7.99% October 27, 2003 $8,333 on each of October 27, 2001 through 2003
September 22, 1993 25,000 6.77% September 22, 2003 single payment at maturity
December 27, 1993 25,000 7.23% December 27, 2003 single payment at maturity
October 27, 1994 25,000 9.05% October 27, 2001 single payment at maturity
October 27, 1994 25,000 9.24% October 27, 2004 single payment at maturity
July 28, 1995 50,000 7.61% July 28, 2007 $10,000 on each of July 28, 2003 through 2007
--------
$200,000
========
1993 Senior Notes. On April 28, 1993, the Company sold $50 million of
7.65% Senior Notes ("1993 Senior Notes") due 2003 to a group of insurance
companies. Annual principal payments of $7.1 million on the 1993 Senior Notes
are due on April 30 of each year from 1997 through 2002, with any remaining
principal and interest outstanding due on April 30, 2003. The Company intends
to finance the $7.1 million payment due in 1997 with amounts available under
the Revolving Credit Facility. 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.
Receivables Facility. In April 1995, the Company entered into an agreement
with Receivables Capital Corporation ("RCC"), as purchaser, and Bank of America
National Trust and Savings Association, as agent, pursuant to which the
Company 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 5.8421% as of December 31, 1996. The Receivables Facility
has a 364-day term and contains financial covenants similar to those in the
Credit Facilities Agreements, as restated and amended, along with certain
covenants regarding the quality of the trade receivables pool. The parties have
renewed the facility through May 29, 1997. The Company anticipates that it will
renew the facility with the current purchaser, enter into a similar agreement
with a new purchaser or repay the facility with amounts available under the
Revolving Credit Facility.
Covenant Compliance. At December 31, 1996, 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, 1996 (000s):
1997.................................... $ 94,643
1998.................................... 15,476
1999.................................... 15,476
2000.................................... 15,477
2001.................................... 40,476
Thereafter.............................. 197,952
--------
Total $379,500
========
39
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 7 - INCOME TAXES
- ---------------------
The provision (benefit) for income taxes for the years ended December 31, 1996,
1995 and 1994 is comprised of (000s):
1996 1995 1994
---- ---- ----
Current:
Federal............................................ $ 1,152 $(3,404) $1,913
State.............................................. - - -
------- -------- ------
Total Current...................................... 1,152 (3,404) 1,913
------- -------- ------
Deferred:
Federal............................................ 12,071 1,192 2,113
State.............................................. 467 54 134
------- -------- ------
Total Deferred..................................... 12,538 1,246 2,247
------- -------- ------
Total tax provision........................... $13,690 $(2,158) $4,160
======= ======== ======
Temporary differences and carryforwards which give rise to the deferred tax
(assets) liabilities at December 31, 1996 and 1995 are as follows (000s):
1996 1995
-------- --------
Property and equipment.......................................... $145,802 $117,885
Differences between the book and tax basis of acquired assets... 16,286 17,146
-------- --------
Total deferred income tax liabilities........................ 162,088 135,031
-------- --------
Alternative Minimum Tax ("AMT") credit carryforwards............ (26,581) (25,450)
Net Operating Loss ("NOL") carryforwards........................ (52,996) (39,608)
-------- --------
Total deferred income tax assets............................. (79,577) (65,058)
-------- --------
Net deferred income taxes.................................... $ 82,511 $ 69,973
======== ========
40
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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, 1996,
1995 and 1994 are summarized as follows (000s):
1996 % 1995 % 1994 %
-------- ----- -------- ------ ------- -----
Income tax (benefit) at statutory rate....... $14,570 35.0 $(2,893) (35.0) $4,033 35.0
State income taxes, net of federal
benefit..................................... 562 1.4 (99) (1.2) 158 1.4
Permanent differences on asset write-downs... - - 1,173 14.2 - -
Reduction of deferred income taxes to
reflect adjustment in acquired NOL
carryforward................................ (900) (2.2) - - - -
Adjustment to prior year income taxes........ (383) (.9) (300) (3.6) - -
Other........................................ (159) (.4) (39) (.5) (31) (.3)
------- ---- ------- ----- ------ ----
Total..................................... $13,690 32.9 $(2,158) (26.1) $4,160 36.1
======= ==== ======= ===== ====== ====
At December 31, 1996, the Company had NOL carryforwards for Federal and state
income tax purposes and AMT credit carryforwards for Federal income tax purposes
of approximately $145.8 million and $26.6 million, respectively. These
carryforwards expire as follows (000s):
Expiration Dates NOL AMT
- ---------------------------- -------- -------
2005........................ $ 499 $ -
2006........................ 478 -
2007........................ 919 -
2008........................ 14,966 -
2009........................ 51,115 -
2010........................ 60,563 -
2011........................ 17,238 -
No expiration............... - 26,581
-------- -------
Total........ $145,778 $26,581
======== =======
The Company believes that the NOL carryforwards and AMT credit carryforwards
will be utilized prior to their expiration because they are substantially offset
by existing taxable temporary differences reversing within the carryforward
period or are expected to be realized by achieving future profitable operations
based on the Company's dedicated and owned reserves, past earnings history,
projections of future earnings and current assets.
NOTE 8 - COMMITMENTS AND CONTINGENT LIABILITIES
- -----------------------------------------------
JN Exploration and Production Litigation
JN Exploration and Production ("JN") is a producer of oil and natural gas that
sold unprocessed natural gas to the Company on a percentage-of-proceeds basis.
The Company processed the natural gas at its Teddy Roosevelt Plant, which is no
longer in operation. In JN Exploration and Production v. Western Gas Resources,
-------------------------------------------------------
Inc. United States District Court for the District of North Dakota, Southwestern
- ----
Division, Civil Action Nos. A1-93-53 and 903-CV-60, JN sued the Company,
alleging that JN was entitled to a portion of a $15 million amendment fee the
Company received in the years 1987 through 1989 from Williston Basin Interstate
Pipeline Company ("WBI"), which had an agreement with the Company to purchase
natural gas. On April 15, 1996, the Court issued a Memorandum and Order granting
JN's summary judgment motion on the issue of liability. On July 11, 1996, the
Court issued a Memorandum and Order setting forth the manner in which damages
are to be calculated. On September 17, 1996, the Court entered a final judgment
against the Company in the amount of $421,000 (including pre-judgment interest).
The Company has appealed the decision and believes that there are meritorious
grounds to reverse the trial court's decision. One other producer has filed a
similar claim. If JN were to prevail on appeal, other producers who sold natural
gas which was processed at the Teddy
41
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Roosevelt Plant during the time period in question may be able to assert similar
claims. The Company believes that it has meritorious defenses to such claims
and, if sued, the Company would defend vigorously against any such claims. At
the present time, it is not possible to predict the outcome of this litigation
or any other producer litigation that might raise similar issues or to estimate
the amount of potential damages.
Kennedy Litigation
M. John Kennedy ("Kennedy") is a producer of oil and natural gas who sells
unprocessed natural gas to the Company on a percentage-of-proceeds basis. The
Company processes the gas at two of the Company's plants located in the Powder
River Basin, Wyoming. In M. John Kennedy v. Western Gas Resources, Inc., Civil
----------------------------------------------
No. 96-CV-0142-B, United States District Court, District of Wyoming, (Originally
filed as Civil Action No. 20522, in the District Court, Sixth Judicial District,
State of Wyoming and removed to the United States District Court by notice filed
by the Company), Kennedy alleges that he is entitled to higher compensation for
residue gas purchased by the Company because the Company allegedly understated
the proceeds attributable to his gas. Kennedy also has claimed that the Company
reduced his revenues by processing gas that had a lower liquid content than did
Kennedy's gas. Kennedy is seeking unspecified damages, including exemplary
damages and prejudgment interest. If Kennedy were to prevail in this matter,
other producers who sold residue gas that was processed by the two plants during
the time period in question may be able to assert similar claims. The Company
believes that it has meritorious defenses to Kennedy's claims and other similar
potential claims. The Company intends to defend this matter vigorously. At the
present time, it is not possible to predict the outcome of this litigation or
any other producer litigation that might raise similar issues or to estimate
the amount of potential damages.
Internal Revenue Service
The Internal Revenue Service ("IRS") has completed its examination of the
Company's returns for the years 1990 and 1991 and has proposed adjustments to
taxable income reflected in such returns that would shift the recognition of
certain items of income and expense from one year to another ("Timing
Adjustments"). To the extent taxable income in a prior year is increased by
proposed Timing Adjustments, taxable income may be reduced by a corresponding
amount in other years. However, the Company would incur an interest charge as a
result of such adjustment. The Company currently is protesting certain of these
proposed adjustments. In the opinion of management, adequate provision has been
made for the additional income taxes and interest that 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.
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 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 Facility and the related underground reservoir. In February 1996 a
global settlement was negotiated in 148 of the 151 condemnation cases requiring
Storage to pay approximately $2.5 million in exchange for receiving all the
property rights it sought to condemn, along with related releases, assignments
and indemnifications. That agreement is expected to be fully implemented in the
first quarter of 1997. The Company considers the $2.5 million payment as a cost
of building the Katy Facility and will capitalize such costs when they are paid.
The remaining three cases not involved in the global settlement are not expected
to have any material impact on the Company and are expected to be resolved
through the normal course of litigation.
Other
The Company is involved in various other litigation and administrative
proceedings arising in the normal course of business. In the opinion of
management, any liabilities that may result from these claims, will not,
individually or in the aggregate, have a material adverse effect on the
Company's financial position or results of operations.
42
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 9 - EMPLOYEE BENEFIT PLANS
- -------------------------------
Profit Sharing Plan
A discretionary profit sharing plan (a defined contribution plan) exists for all
Company employees meeting certain service requirements. The Company may make
annual contributions to the plan as determined by the Board of Directors and
provides for a match of 25% of employee contributions on the first 4% of
employee compensation contributed. Contributions are made to common/collective
trusts for which Fidelity Management Trust Company acts as trustee. The
discretionary contributions were $1.7 million, $1.3 million and $1.3 million,
for the years ended December 31, 1996, 1995 and 1994, respectively. The
matching contributions were $256,000, $183,000 and $264,000 for the years ended
December 31, 1996, 1995 and 1994, respectively.
$5.40 Stock Option Plan
In April 1987 and amended in February 1994, the Partnership adopted an employee
option plan ("$5.40 Plan") that authorizes granting options to employees to
purchase 483,000 common units in the Partnership. Pursuant to the Restructuring,
the Company assumed the Partnership's obligation under the employee option plan.
The plan was amended upon the Restructuring to allow each holder of existing
options to exercise such options and acquire one share of Common Stock for each
common unit they were originally entitled to purchase. The exercise price and
all other terms and conditions for the exercise of such options issued under the
amended plan were the same as under the plan, except that the Restructuring
accelerated the time upon which certain options may be exercised. Options may
not be exercised after May 31, 1997. The Company has entered into agreements
committing the Company to loan to certain employees an amount sufficient to
exercise their options, provided that the Company will not loan in excess of 25%
of the total amount available to the employee in any one year. The Company will
forgive any such loan and associated accrued interest on July 2, 1997, if the
employee is then employed by the Company. Under the terms of a severance
agreement, the Company extended the maturity date of one former officer's loans
to December 31, 2000. As of December 31, 1996 and 1995, loans and accrued
interest related to 102,123 and 100,374 shares of Common Stock, respectively,
totaling $677,000 and $637,000, respectively, 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 later 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 employees an
amount sufficient to exercise their options as each portion of their options
vests. The Company will forgive such loans and associated accrued interest if
the employee has been continuously employed by the Company for four years after
the date of each loan increment. In January 1997, the Board of Directors voted
to extend the maturity for each of the loan increments by three years for the
first series of maturities and by two years for all other maturities. During
1996, under the terms of a severance agreement, the Company extended the
maturity date of one former officer's loans to December 31, 2000. In addition,
under the terms of a severance agreement, the loans of a former officer are
being forgiven over the life of the original loan forgiveness schedule. As of
December 31, 1996 and 1995, loans and accrued interest related to 118,750 and
125,000 shares of Common Stock, respectively, totaling $1.6 million and $1.5
million, respectively, were outstanding under these terms.
1993 Stock Option Plan
The 1993 Stock Option Plan ("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.
43
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED 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.
The following table summarizes the number of stock options exercisable and
available for grant under the Company's benefit plans:
Key Employee Directors'
$5.40 Plan Plan Plan 1993 Plan
---------- ------------ ---------- ---------
Exercisable at December 31, 1994........................ 75,348 18,750 6,375 64,025
Exercisable at December 31, 1995........................ 47,571 37,500 9,750 170.344
Exercisable at December 31, 1996........................ 33,148 56,250 11,000 288,438
Available for grant at December 31, 1994................ - 31,250 1,250 362,414
Available for grant at December 31, 1995................ - 31,250 1,250 309,872
Available for grant at December 31, 1996................ - 31,250 1,250 4,734
The following table summarizes the stock option activity under the Company's
benefit plans:
Number of Shares
Per Share -----------------------------------------------------------
Price Key Employee Directors'
Range $5.40 Plan Plan Plan 1993 Plan
--------------- ---------- ------------ ---------- ---------
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
Granted..................... 13.88 - 18.63 - - - 351,733
Exercised................... 5.40 (14,423) - - -
Forfeited or canceled....... $13.25 - $35.00 - - - (46,595)
-------- ------- ------- -------
Balance 12/31/96............. 33,148 75,000 13,500 993,199
======== ======= ======= =======
44
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following table summarizes the weighted average option exercise price
information under the Company's benefit plans:
Key Employee Directors'
$5.40 Plan Plan Plan 1993 Plan
---------- ------------ ---------- ---------
Balance 12/31/93.......... $5.40 $20.47 $12.30 $32.75
Granted................. - - 19.94 20.17
Exercised............... 5.40 10.71 15.00 -
Forfeited or canceled... 5.40 10.71 15.00 32.84
Balance 12/31/94.......... 5.40 24.49 14.13 26.40
Granted................. - - - 20.68
Exercised............... 5.40 10.71 - -
Forfeited or canceled... 5.40 - - 27.53
Balance 12/31/95.......... 5.40 30.23 14.13 25.11
Granted................. - - - 14.63
Exercised............... 5.40 - - -
Forfeited or canceled... - - - 27.05
Balance 12/31/96.......... $5.40 $30.23 $14.13 $21.31
SFAS No. 123 encourages companies to record compensation expense for stock-based
compensation plans at fair value. As permitted under SFAS No. 123, the Company
has elected to continue to measure compensation costs for such plans as
prescribed by APB No. 25. SFAS No. 123 requires pro forma disclosures in 1996
for the years ended December 31, 1996 and 1995. Such information was only
calculated for the options granted in 1995 and 1996 under the 1993 Plan as there
were no grants under any other plans. The weighted average fair value of
options granted of $10.18 and $6.03 for the years ended December 31, 1996 and
1995, respectively, were estimated using the Black-Scholes option-pricing model
with the following assumptions:
1996 1995
------ ------
Risk-free interest rate.......... 6.35% 5.65%
Expected life (in years)......... 7 8
Expected volatility.............. 37% 32%
Expected dividends (quarterly)... $ .05 $ .05
Had compensation expense for the Company's 1996 and 1995 grants for stock-based
compensation plans been determined consistent with the fair value method under
SFAS No. 123, the Company's net income (loss), income (loss) attributable to
common stock and earnings (loss) per share of common stock would approximate the
pro forma amounts below (000s, except per share amounts):
1996 1995
----------------------- -------------------------
As Reported Pro forma As Reported Pro forma
----------- --------- ------------ ----------
Net income (loss)................................ $27,941 $27,891 $ (6,108) $ (6,108)
Net income (loss) attributable to common stock... 17,502 17,452 (21,539) (21,539)
Earnings (loss) per share of common stock........ $ .66 $ .66 $ (.84) $ (.84)
The 1993 Plan dictates that the options granted will vest 20% each year on
the anniversary of the date of grant commencing with the first anniversary. As
a result, no compensation expense, as defined under SFAS No. 123, is recognized
in the year options are granted. In addition, the fair market value of the
options at grant date is amortized over this vesting schedule for purposes of
calculating compensation expense. In the initial years of implementation of SFAS
No. 123, the pro forma compensation expense will not be representative of future
pro forma expense.
45
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 10 - SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
- ----------------------------------------------------------------------
(UNAUDITED):
- ------------
Costs
The following tables set forth capitalized costs at December 31, 1996, 1995 and
1994 and costs incurred for oil and gas producing activities for the years ended
December 31, 1996, 1995 and 1994 (000s):
1996 1995 1994
-------- -------- --------
Capitalized costs:
Proved properties................................................ $140,871 $136,499 $136,861
Unproved properties.............................................. 8,064 6,279 7,448
-------- -------- --------
Total............................................................. 148,935 142,778 144,309
Less accumulated depletion....................................... (58,548) (46,792) (35,346)
-------- -------- --------
Net capitalized costs............................................. $ 90,387 $ 95,986 $108,963
======== ======== ========
The Company's share of Redman Smackover's net capitalized costs... $ 4,385 $ 5,216 $ -
======== ======== ========
Costs incurred:
Acquisition of properties
Proved........................................................... $ 242 $ 1,591 $ 2,523
Unproved......................................................... 909 128 1,617
Development costs................................................. 3,893 3,035 3,555
Exploration costs................................................. 2,581 1,102 2,465
-------- -------- --------
Total costs incurred.............................................. $ 7,625 $ 5,856 $ 10,160
======== ======== ========
The Company's share of Redman Smackover's costs incurred.......... $ 8 $ 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, 1996,
1995 and 1994 are as follows (000s):
1996 1995 1994
--------- --------- ---------
Revenues from sale of oil and gas:
Sales................................................. $ 1,821 $ 2,490 $ 3,402
Transfers............................................. 31,733 29,739 37,335
-------- -------- --------
Total............................................... 33,554 32,229 40,737
Production costs....................................... (4,256) (4,160) (4,960)
Exploration costs...................................... (898) (956) (489)
Depreciation, depletion and amortization............... (11,756) (15,081) (17,469)
Income tax expense..................................... (6,261) (4,429) (6,030)
-------- -------- --------
Results of operations.................................. $ 10,383 $ 7,603 $ 11,789
======== ======== ========
The Company's share of Redman Smackover's operations... $ 1,745 $ 324 $ -
======== ======== ========
46
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Reserve Quantity Information
Reserve estimates are subject to numerous uncertainties inherent in the
estimation of quantities of proved reserves and in the projection of future
rates of production and the timing of development expenditures. The accuracy of
such estimates is a function of the quality of available data and of engineering
and geological interpretation and judgment. Estimates of economically
recoverable reserves and of future net cash flows expected therefrom prepared by
different engineers or by the same engineers at different times may vary
substantially. Results of subsequent drilling, testing and production may cause
either upward or downward revisions of previous estimates. Further, the volumes
considered to be commercially recoverable fluctuate with changes in prices and
operating costs. Any significant revision of reserve estimates could materially
adversely affect the Company's financial condition and results of operations.
The following table sets forth information for the years ended December 31,
1996, 1995 and 1994 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, 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
Revisions of previous estimates............................ (2,147) 286
Purchases of reserves in place............................. 2,372 -
Production................................................. (13,014) (158)
------- ----
December 31, 1996.......................................... 96,031 843
======= ====
The Company's share of Redman Smackover's proved reserves:
December 31, 1995.......................................... 12,647 -
======= ====
December 31, 1996.......................................... 10,811 -
======= ====
Standardized Measures of Discounted Future Net Cash Flows
Estimated discounted future net cash flows and changes therein were determined
in accordance with SFAS No. 69, "Disclosures about Oil and Gas Producing
Activities." Certain information concerning the assumptions used in computing
the valuation of proved reserves and their inherent limitations are discussed
below. The Company believes such information is essential for a proper
understanding and assessment of the data presented.
Future cash inflows are computed by applying year end prices of oil and gas
relating to the Company's 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
47
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
indirectly from factors outside of the Company's control, such as unintentional
delays in development, changes in prices or regulatory controls. The reserve
valuation further assumes that all reserves will be disposed of by production.
However, if reserves are sold in place, additional economic considerations could
also affect the amount of cash eventually realized.
Future development and production costs are computed by estimating the
expenditures to be incurred in developing and producing the proved oil and gas
reserves at the end of the year, based on year end costs and assuming
continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate year end
statutory tax rates, with consideration of future tax rates already legislated,
to the future 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, 1996, 1995 and
1994 is as follows (000s):
1996 1995 1994
---------- --------- ---------
Future cash inflows.......................................................... $ 305,095 $230,986 $239,188
Future production costs...................................................... (54,306) (52,442) (50,214)
Future development costs..................................................... (1,728) (3,564) (9,230)
Future income tax expense.................................................... (37,870) (18,386) (16,783)
--------- -------- --------
Future net cash flows........................................................ 211,191 156,594 162,961
10% annual discount for estimated timing of cash flows....................... (100,474) (74,832) (67,230)
--------- -------- --------
Standardized measure of discounted future net cash flows relating to
proved oil and gas reserves................................................ $ 110,717 $ 81,762 $ 95,731
========= ======== ========
The Company's share of Redman Smackover's standardized measure of
discounted future net cash flows relating to proved oil and gas reserves... $ 5,684 $ 4,665 $ -
========= ======== ========
Principal changes in the Company's estimated discounted future net cash flows
for the years ended December 31, 1996, 1995 and 1994 are as follows (000s):
1996 1995 1994
---------- --------- ---------
January 1..................................................................... $ 81,762 $ 95,731 $124,125
Sales and transfers of oil and gas produced, net of production costs........ (29,298) (28,069) (35,777)
Net changes in prices and production costs related to future production..... 61,888 10,788 (33,363)
Development costs incurred during the period................................ 3,893 3,035 3,555
Changes in estimated future development costs............................... (2,057) 2,631 (162)
Revisions of previous quantity estimates.................................... 2,554 (12,147) 14,830
Purchases of reserves in place.............................................. 5,266 - 3,882
Accretion of discount....................................................... 8,176 9,573 12,413
Net change in income taxes.................................................. (19,484) (1,603) 8,499
Other, net.................................................................. (1,983) 1,823 (2,271)
--------- -------- --------
December 31................................................................... $ 110,717 $ 81,762 $ 95,731
========= ======== ========
48
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (COMSOLIDATED)
NOTE 11 - 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
---------- ---------- --------- --------
1996 quarter ended:
March 31..................................................................... $ 480,714 $ 33,223 $ 10,233 $ .30
June 30...................................................................... 446,223 24,029 5,432 .11
September 30................................................................. 467,721 19,275 2,881 .01
December 31.................................................................. 696,351 28,952 9,395 .24
---------- -------- -------- -----
$2,091,009 $105,479 $ 27,941 $ .66
========== ======== ======== =====
1995 quarter ended:
March 31..................................................................... $ 303,701 $ 18,444 $ 1,941 $ (.05)
June 30...................................................................... 304,408 17,671 (403)(b) (.28)
September 30................................................................. 286,705 16,518 462 (.08)
December 31.................................................................. 362,170 22,578 (8,108)(c) (.43)
---------- -------- -------- -------
$1,256,984 $ 75,211 $ (6,108) $ (.84)
========== ======== ======== =======
(a) Excludes selling and administrative, interest, restructuring and income tax
expenses.
(b) Includes costs associated with a cost reduction program to reduce operating
and selling and administrative expenses. As a result of this program, a
$1.3 million after-tax, restructuring charge was incurred, primarily related
to employee severance costs.
(c) Includes an after-tax, non-cash expense resulting from the adoption of SFAS
No. 121 of $12.4 million.
49
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 21,
1997 and is hereby incorporated by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
(1) Financial Statements:
Reference is made to page 23 for a list of all financial statements
filed as a part of this report.
(2) Financial Statement Schedules:
None required.
(3) Exhibits:
3.1 Certificate of Incorporation of Western Gas Resources, Inc. (Filed
as exhibit 3.1 to Western Gas Resources, Inc.'s Registration
Statement on Form S-1, Registration No. 33-31604 and incorporated
herein by reference).
3.2 Certificate of Amendment to the Certificate of Incorporation of
Western Gas Resources, Inc. (Filed as exhibit 3.2 to Western Gas
Resources, Inc.'s Registration Statement on Form S-1, Registration
No. 33-31604 and incorporated herein by reference).
3.3 Certificate of Designation of 7.25% Cumulative Senior Perpetual
Convertible Preferred Stock of the Company (Filed as exhibit 3.5 to
Western Gas Resources, Inc.'s Registration Statement on Form S-1,
Registration No. 33-43077 dated November 14, 1991 and incorporated
herein by reference).
3.4 Certificate of Designation of $2.28 Cumulative Preferred Stock of
the Company. (Filed as exhibit 3.6 to Western Gas Resources, Inc.'s
Registration Statement of Form S-1, Registration No. 33-53786 dated
November 12, 1992 and incorporated herein by reference).
3.5 Certificate of Designation of the $2.625 Cumulative Convertible
Preferred Stock of the Company (Filed under cover of Form 8-K dated
February 24, 1994 and incorporated herein by reference).
50
3.6 Amended and restated of the By-laws of Western Gas Resources, Inc.
as adopted by the Board of Directors on September 6, 1996. (Filed as
exhibit 3.9 to Western Gas Resources, Inc.'s Form 10-Q for the nine
months ended September 30, 1996 and incorporated herein by
reference).
10.1 Restated Profit-Sharing Plan and Trust Agreement of Western Gas
Resources, Inc. (Filed as exhibit 10.8 to Western Gas Resources,
Inc.'s Registration Statement on Form S-4, Registration No. 33-39588
dated March 27, 1991 and incorporated herein by reference).
10.2 Western Gas Resources, Inc. Key Employees' Incentive Stock Option
Plan (Filed as exhibit 10.13 to Western Gas Resources, Inc.'s
Registration Statement on Form S-4, Registration No. 33-39588 dated
March 27, 1991 and incorporated herein by reference).
10.3 Registration Rights Agreement among Western Gas Resources, Inc.,
WGP, Inc., Heetco, Inc., NV, Dean Phillips, Inc., Sauvage Gas
Company and Sauvage Gas Service, Inc. (Filed as exhibit 10.14 to
Western Gas Resources, Inc.'s Registration Statement on Form S-4,
Registration No. 33-39588 dated March 27, 1991 and incorporated
herein by reference).
10.4 Amendment No. 1 to Registration Rights Agreement as of May 1, 1991
between Western Gas Resources, Inc., Bill Sanderson, WGP, Inc., Dean
Phillips, Inc., Heetco, Inc., NV, Sauvage Gas Company and Sauvage
Gas Service, Inc. (Filed as exhibit 4.2 to Western Gas Resources,
Inc.'s Form 10-Q for the quarter ended June 30, 1991 and
incorporated herein by reference).
10.5 Second Amendment and First Restatement of Western Gas Processors,
Ltd. Employees' Common Units Option Plan (Filed as exhibit 10.6 to
Western Gas Resources, Inc.'s Registration Statement on Form S-1,
Registration No. 33-43077 dated November 14, 1991 and incorporated
herein by reference).
10.6 Agreement to provide loans to exercise key employees' common stock
options (Filed as exhibit 10.26 to Western Gas Resources, Inc.'s
Annual Report on Form 10-K for the fiscal year ended December 31,
1991 and incorporated herein by reference).
10.7 Agreement to provide loans to exercise employees' common stock
options (Filed as exhibit 10.27 to Western Gas Resources, Inc.'s
Annual Report on Form 10-K for the fiscal year ended December 31,
1991 and incorporated herein by reference).
10.8 Note Purchase Agreement (without exhibits) dated as of April 1,
1993 by and between the Company and the Purchasers for $50,000,000,
7.65% Senior Notes Due April 30, 2003 (Filed as exhibit 10.48 to
Western Gas Resources Inc.'s Form 10-Q for the six months ended June
30, 1993 and incorporated herein by reference).
51
10.9 General Partnership Agreement (without exhibits), dated August 10,
1993 for Westana Gathering Company by and between Western Gas
Resources -Oklahoma, Inc. (a subsidiary of the Company) and
Panhandle Gathering Company (Filed as exhibit 10.50 to Western Gas
Resources Inc.'s Form 10-Q for the six months ended June 30, 1993
and incorporated herein by reference).
10.10 Amendment to General Partnership Agreement dated August 10, 1993 by
and between Western Gas Resources -Oklahoma, Inc. (a subsidiary of
the Company) and Panhandle Gathering Company (Filed as exhibit 10.51
to Western Gas Resources Inc.'s Form 10-Q for the six months ended
June 30, 1993 and incorporated herein by reference).
10.11 Amendment No. 1 to Note Purchase Agreement dated as of August 31,
1993 by and among the Company and the Purchasers (Filed as exhibit
10.61 to Western Gas Resources Inc.'s Form 10-Q for the nine months
ended September 30, 1993 and incorporated herein by reference).
10.12 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).
10.13 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).
10.14 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).
52
10.15 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).
10.16 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).
10.17 Second Amendment to First Restated Loan Agreement (Revolver) 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
10.36 to Western Gas Resources, Inc.'s Form 10-Q for the three months
ended March 31, 1995 and incorporated herein by reference).
10.18 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).
10.19 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).
10.20 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).
10.21 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).
10.22 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).
10.23 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).
10.24 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).
53
10.25 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).
10.26 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 and incorporated
herein by reference).
10.27 Second Amended and Restated Master Shelf Agreement effective January
31, 1996 by and between Western Gas Resources, Inc. and Prudential
Company of America. (Filed as exhibit 10.49 to Western Gas Resources,
Inc.'s Form 10-K for the year ended December 31, 1995 and incorporated
herein by reference).
10.28 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. (Filed as exhibit 10.50 to Western Gas
Resources, Inc.'s Form 10-K for the year ended December 31, 1995 and
incorporated herein by reference).
10.29 Fourth Amendment to First Restated Loan Agreement (Revolver) dated
November 29, 1995 by and among Western Gas Resources, Inc. and
NationsBank, as agent, and the Lenders. (Filed as exhibit 10.51 to
Western Gas Resources, Inc.'s Form 10-K for the year ended December
31, 1995 and incorporated herein by reference).
10.30 Senior Note Purchase Agreement dated November 29, 1995 by and among
Western Gas Resources, Inc. and the Purchasers identified therein.
(Filed as exhibit 10.52 to Western Gas Resources, Inc.'s Form 10-K for
the year ended December 31, 1995 and incorporated herein by
reference).
10.31 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. (Filed as exhibit 10.53 to
Western Gas Resources, Inc.'s Form 10-K for the year ended December
31, 1995 and incorporated herein by reference).
10.32 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. (Filed as exhibit 10.54 to Western Gas
Resources, Inc.'s Form 10-K for the year ended December 31, 1995 and
incorporated herein by reference).
10.33 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 Resource s, Inc.'s Form 10-K for the year ended December
31, 1993).
10.34 Extension of Receivables Purchase Agreement dated as of February 28,
1995, among Western Gas Resources, Inc., as Seller, Receivable Capital
Corporation, as Purchaser, and Bank of America National Trust and
Savings Association, as Agent. (Filed as exhibit 10.56 to Western Gas
Resources, Inc.'s Form 10-Q for the three months ended March 31, 1996
and incorporated herein by reference).
10.35 Amendment No. 2 to Receivables Purchase Agreement dated as of February
28, 1995, by and among Western Gas Resources, Inc., as Seller,
Receivable Capital Corporation, as Purchaser, and Bank of America
National Trust and Savings Association, as Agent. (Filed as exhibit
10.57 to Western Gas Resources, Inc.'s Form 10-Q for the six months
ended June 30, 1996 and incorporated herein by reference).
10.36 Amendment No. 3 to Receivables Purchase Agreement dated as of October
16, 1996, by and among Western Gas Resources, Inc., as Seller,
Receivables Capital Corporation, as Purchaser, and Bank of America
National Trust and Savings Association, as Agent. (Filed as exhibit
10.58 to Western Gas Resources, Inc.'s Form 10-Q for the nine months
ended September 30, 1996 and incorporated herein by reference).
10.37 Eighth Amendment to Third Restated Loan Agreement (Term) dated October
16, 1996, by and among Western Gas Resources, Inc. and NationsBank of
Texas, N.A., as agent, and the Lenders. (Filed as exhibit 10.59 to
Western Gas Resources, Inc.'s Form 10-Q for the nine months ended
September 30, 1996 and incorporated herein by reference).
10.38 Sixth Amendment to First Restated Loan Agreement (Revolver) dated
October 16, 1996, by and among Western Gas Resources, Inc. and
NationsBank of Texas, N.A., as agent, and the Lenders. (Filed as
exhibit 10.60 to Western Gas Resources, Inc.'s Form 10-Q for the nine
months ended September 30, 1996 and incorporated herein by reference).
54
10.39 Seventh Amendment to First Restated Loan Agreement (Revolver) dated
December 19, 1996, by and among Western Gas Resources, Inc. and
NationsBank of Texas, N.A., as agent, and the Lenders.
11.1 Statement regarding computation of per share earnings.
21.1 List of Subsidiaries of Western Gas Resources, Inc.
23.1 Consent of Price Waterhouse LLP, independent accountants.
(b) Reports on Form 8-K:
A report on Form 8-K was filed on November 1, 1996 to file certain consents
related to the Company's shelf registrations.
A report on Form 8-K was filed on November 22, 1996 to file certain consents,
Underwriting Agreement and Pricing Agreement related to the Company's offering
of 6,325,000 shares of common stock.
(c) Exhibits required by Item 601 of Regulation S-K. See (a) (3) above.
55
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Denver,
State of Colorado on March 14, 1997.
WESTERN GAS RESOURCES, INC.
---------------------------
(Registrant)
By: /S/ Brion G. Wise
-----------------
Brion G. Wise
Chairman of the Board and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.
/S/ Brion G. Wise Chairman of the Board, Chief Executive Officer March 14, 1997
- ----------------------
Brion G. Wise and Director
/S/ W. L. Stonehocker Vice Chairman of the Board and Director March 14, 1997
- ----------------------
Walter L. Stonehocker
/S/ B. M. Sanderson Director March 14, 1997
- ----------------------
Bill M. Sanderson
Director March 14, 1997
- ----------------------
Richard B. Robinson
/S/ Dean Phillips Director March 14, 1997
- ----------------------
Dean Phillips
Director March 14, 1997
- ----------------------
Ward Sauvage
/S/ James A. Senty Director March 11, 1997
- ----------------------
James A. Senty
Director March 14, 1997
- ----------------------
Joseph E. Reid
/S/ William J. Krysiak Vice President - Finance (Principal Financial March 14, 1997
- ----------------------
William J. Krysiak and Accounting Officer)
56