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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] Annual report pursuant to section 13 or 15(d) of the Securities Exchange
Act of 1934 for the fiscal year ended December 31, 1998 or
[ ] Transition report pursuant to section 13 or 15(d) of the Securities
Exchange Act of 1934 [No Fee Required] for the transition period from
_________________ to _________________
Commission file number 1-10389
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WESTERN GAS RESOURCES, INC.
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(Exact name of registrant as specified in its charter)
Delaware 84-1127613
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
12200 N. Pecos Street, Denver, Colorado 80234-3439
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(Address of principal executive offices) (Zip Code)
(303) 452-5603
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Registrant's telephone number, including area code
No Changes
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(Former name, former address and former fiscal year, if changed since last
report)
Title of each class Name of exchange on which registered
- ----------------------------- ------------------------------------
Common Stock, $0.10 par value New York Stock Exchange
$2.28 Cumulative Preferred Stock,
$0.10 par value New York Stock Exchange
$2.625 Cumulative Convertible Preferred
Stock, $0.10 par value New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No _____
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The aggregate market value of voting common stock held by non-affiliates of the
registrant on March 15, 1999 was $130,274,224
As of March 15, 1999, there were 32,147,993 shares of Common Stock outstanding.
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, 1999.
Indicate by check mark if disclosure of delinquent filers to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
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1
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................................................. 5
Gas Gathering, Processing, Storage and Transmission.................. 6
Significant Acquisitions, Projects and Dispositions.................. 7
Marketing............................................................ 10
Producing Properties................................................. 11
Competition.......................................................... 12
Regulation........................................................... 12
Employees............................................................ 13
3. Legal Proceedings.................................................... 13
4. Submission of Matters to a Vote of Security Holders.................. 13
II. 5. Market for Registrant's Common Equity and Related Stockholder Matters 14
6. Selected Financial Data.............................................. 15
7. Management's Discussion and Analysis of Financial Condition and
Results of Operations................................................ 16
8. Financial Statements and Supplementary Data.......................... 27
9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure................................................. 58
III. 10. Directors and Executive Officers of the Registrant................... 58
11. Executive Compensation............................................... 58
12. Security Ownership of Certain Beneficial Owners and Management....... 58
13. Certain Relationships and Related Transactions....................... 58
IV. 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K..... 58
2
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
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 sales delivery point. The Company designs,
constructs, owns and operates natural gas gathering, processing, treating and
storage facilities in major gas-producing basins in the Rocky Mountain, Mid-
Continent, Gulf Coast and Southwestern regions of the United States. The
Company connects producers' wells to its gathering systems for delivery to its
processing or treating plants, processes the natural gas to extract natural gas
liquids ("NGLs") and treats the natural gas in order to meet pipeline
specifications. The Company markets gas and NGLs nationwide and in Canada,
providing risk management, storage, transportation, scheduling, peaking and
other services to a variety of customers. The Company owns and operates certain
producing properties, primarily in Wyoming and Louisiana. The Company also
explores and develops gas reserves, primarily in Wyoming, in support of its
existing facilities.
Historically, the Company has derived over 95% of its revenues from the sale of
gas and NGLs. Set forth below are the Company's revenues by type of operation
(000s):
Year Ended December 31,
----------------------------------------------------------
1998 % 1997 % 1996 %
---------- ------ ---------- ------ ---------- ------
Sale of gas...................................... $1,611,521 75.5 $1,657,479 69.5 $1,440,882 68.9
Sale of NGLs..................................... 449,696 21.1 611,969 25.7 561,581 26.9
Processing, transportation and storage revenues.. 44,743 2.1 40,906 1.7 44,943 2.1
Sale of electric power........................... 20 - 59,477 2.5 30,667 1.5
Other, net....................................... 27,586 1.3 15,429 .6 12,936 .6
---------- ----- ---------- ----- ---------- -----
$2,133,566 100.0 $2,385,260 100.0 $2,091,009 100.0
========== ===== ========== ===== ========== =====
Historically, the Company has expanded through acquisitions, joint ventures,
internal project development and increased marketing activity. This expansion
has strengthened the Company's position in major producing basins and increased
its access to natural gas markets. The Company's current strategy focuses on
developing opportunities within the active basins in which it operates. The
table below illustrates the Company's growth over the last five years:
Average for the Year Ended
Average --------------------------------------
Average NGL Gas Gas NGL
Gas Sales Sales Throughput Production Production
(MMcf/D) (MGal/D) (MMcf/D) (MMcf/D) (MGal/D)
---------- -------- ----------- ----------- ------------
December 31, 1993...... 755 2,941 804 575 2,239
December 31, 1998...... 2,200 4,730 1,162 984 1,912
% increase (decrease).. 191 61 45 71 (15)
The Company's long-term four-part business plan is designed to increase
profitability through: (i) investing in projects that complement and extend its
core gas gathering, processing, production and marketing business; (ii) creating
ventures with producers who dedicate additional acreage to the Company; (iii)
maintaining or expanding its energy sales volumes and margins by maximizing its
asset base, firm transportation and storage contracts and other contractual
arrangements; and (iv) optimizing the profitability of existing operations and
in certain cases, considering the disposal of non-growth assets.
Historically, crude oil prices have been volatile and the oil and gas industry
is currently experiencing ten year lows in these prices. As of March 1, 1999
such prices had declined to approximately $12.25 per barrel. Most NGL value is
tied closely to crude oil, accordingly this pricing environment is having a
detrimental effect on the Company's results of operations.
The Company's 1999 plan provides for the improvement of the balance sheet and
liquidity while ensuring the continued development of its two primary growth
projects, the Powder River Basin coal bed methane and Southwest Wyoming
operations. In order to reduce the Company's overall debt level and provide it
with additional liquidity, the Company has signed agreements in March 1999
providing for the sale of its Giddings Gathering System and the Katy Facility
for total proceeds of approximately $136 million. These transactions will
result in an after-tax loss in 1999 of approximately $14.9 million and are
expected to close in the second quarter of 1999, subject to various regulatory
approvals and the satisfaction of certain contractual conditions. See further
discussion in "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Business Strategy."
This section, as well as other sections in this Form 10-K, contain "forward-
looking statements" within the meaning of the Private Securities Litigation
Reform Act of 1995, which can be identified by the use of forward-looking
terminology, such as "may," "intend,"
3
"will," "expect," "anticipate," "estimate," or "continue" or the negative
thereof or other variations thereon or comparable terminology. This Form 10-K
contains forward-looking statements regarding the expansion of the Company's
gathering operations, its project development schedules, marketing plans,
throughput capacity and anticipated volumes that involve a number of risks and
uncertainties, including the composition of gas to be treated and the drilling
schedules and success of the producers whose acreage is dedicated to the
Company's facilities. In addition to the important factors referred to herein,
numerous other factors affecting the gas processing industry generally and in
the markets for gas and NGLs in which the Company operates, could cause actual
results to differ materially. See further discussion in "Financial Statements
and Supplementary Data - Notes to Consolidated Financial Statements - Note 2 -
Summary of Significant Accounting Policies - Use of Estimates and Significant
Risks."
The Company's principal offices are located at 12200 North Pecos Street, Denver,
Colorado 80234-3439, and its telephone number is (303) 452-5603. The Company
was incorporated in Delaware in 1989.
4
PRINCIPAL FACILITIES
The following table provides information concerning the Company's principal
facilities. The Company also owns and operates several smaller treating and
processing facilities located in the same areas as its other facilities.
Average for the Year Ended
December 31, 1998
Gas Gas -------------------------------------------
Gathering Throughput Gas Gas NGL
Year Placed Systems Capacity Throughput Production Production
Plant Facilities (1) In Service Miles(2) (MMcf/D)(3) (MMcf/D)(4) (MMcf/D)(5) (MGal/D)(5)
- --------------------------------- ----------- -------------------- ---------------- -------------- -------------- -----------
Texas
Bethel Treating (6)............ 1997 86 350 61 57 -
Edgewood (6)(7)(8)............. 1964 - - 20 6 48
Giddings Gathering (16)........ 1979 661 80 49 41 72
Gomez Treating................. 1971 385 280 118 112 -
Midkiff/Benedum................ 1955 2,138 165 151 100 966
Mitchell Puckett Gathering..... 1972 86 85 80 53 1
MiVida Treating (6)............ 1972 289 150 58 56 -
Rosita Treating................ 1973 - 60 49 49 -
Louisiana
Black Lake..................... 1966 56 75 13 8 27
Toca (7)(9).................... 1958 - 160 72 68 56
Wyoming
Coal Bed Methane
Gathering..................... 1990 378 95 73 67 -
Granger (7)(10)(11)(12)........ 1987 431 235 154 142 185
Hilight Complex (7)............ 1969 622 80 41 35 93
Kitty/Amos Draw (7)............ 1969 313 17 10 7 52
Lincoln Road (12).............. 1988 149 50 29 27 28
Newcastle (7).................. 1981 146 5 2 2 17
Red Desert (7)................. 1979 111 42 19 17 34
Reno Junction (10)............. 1991 - - - - 49
Oklahoma
Arkoma......................... 1985 64 8 5 5 -
Chaney Dell.................... 1966 2,049 180 66 52 212
Westana........................ 1986 789 45 61 53 65
New Mexico
San Juan River (6)............. 1955 139 60 27 24 2
Utah
Four Corners Gathering......... 1988 104 15 4 3 5
----- ----- ----- ---- -----
Total......................... 8,996 2,237 1,162 984 1,912
===== ===== ====== ===== =====
Average for the
Year Ended
December 31, 1998
Interconnect --------------------
and Gas Storage Pipeline Gas
Storage and Year Placed Transmission Capacity Capacity Throughput
Transmission Facilities (1) In Service Miles(2) (Bcf)(2) (MMcf/D)(2) (MMcf/D)(4)
- --------------------------------- ----------- ------------ ------------ ---------------- -------------
Katy Facility (13)(16)........... 1994 17 20 - 200
MIGC (14)........................ 1970 245 - 130 98
MGTC (15)........................ 1963 252 - 18 10
----- ----- --- ----
Total.......................... 514 20 148 308
===== ===== ==== ====
_________________________________
Footnotes on following page.
5
(1) The Company's interest in all facilities is 100% except for Midkiff/Benedum
(73%); Black Lake (69%); Lincoln Road (72%); Westana Gathering Company
("Westana") (50%); Newcastle (50%) and Coal Bed Methane Gathering (50%).
All facilities are operated by the Company, and all data include interests
of the Company, other joint interest owners and producers of gas volumes
dedicated to the facility.
(2) Gas gathering systems miles, interconnect and transmission miles, gas
storage capacity and pipeline capacity are as of December 31, 1998.
(3) Gas throughput capacity is as of December 31, 1998 and represents capacity
in accordance with design specifications unless other constraints exist,
including permitting or field compression limits. MMcf/D means million
cubic feet per day.
(4) Aggregate wellhead natural gas volumes collected by a gathering system,
aggregate volumes delivered over the header at the Katy Hub and Gas Storage
Facility (the "Katy Facility") or volumes transported by a pipeline.
(5) Volumes of gas and NGLs are allocated to a facility when a well is
connected to that facility; volumes exclude NGLs fractionated for third
parties. MGal/D means thousand gallons per day.
(6) Sour gas facility (capable of processing or treating gas containing
hydrogen sulfide and/or carbon dioxide).
(7) Fractionation facility (capable of fractionating raw NGLs into end-use
products).
(8) On October 29, 1998, the Company sold its Edgewood gathering system,
including its undivided interest in the producing properties associated
with this system.
(9) Straddle plant (a plant located near a transmission pipeline that processes
gas dedicated to or gathered by a pipeline company or another third party).
(10) NGL production includes conversion of third-party feedstock to iso-butane.
(11) In February 1998, the Company sold a 50% undivided interest in a small
portion of the Granger gathering system for approximately $4.0 million.
This amount approximated the Company's cost in such facilities.
(12) The Company and its joint venture partner at the Lincoln Road facility have
agreed to process such gas at the Company's Granger facility as long as
there is available capacity at the Granger facility. Accordingly,
operations at the Lincoln Road facility were temporarily suspended for the
period between February 1998 and June 1998.
(13) Hub and gas storage facility.
(14) MIGC is an interstate pipeline located in Wyoming and is regulated by the
FERC.
(15) MGTC is a public utility located in Wyoming and is regulated by the Wyoming
Public Service Commission.
(16) In March 1999, the Company signed agreements for the sale of these
facilities. These transactions are anticipated to close in the second
quarter of 1999, subject to various approvals.
Largely as a result of low commodity prices, primarily affecting NGL products,
the Company has reduced its budget for capital expenditures in 1999 from the
levels expended in 1997 and 1998. Capital expenditures related to existing
operations are expected to be approximately $67.0 million during 1999,
consisting of the following: (i) capital expenditures related to gathering,
processing and pipeline assets are expected to be approximately $39.6 million,
of which $6.3 million is for maintaining existing facilities; (ii) capital
expenditures on exploration and production activities are expected to be
approximately $24.6 million; and (iii) capital expenditures for miscellaneous
items are expected to be approximately $2.8 million. Overall, capital
expenditures in the Powder River Basin coal bed methane development and in
Southwest Wyoming operations represent 53% and 22%, respectively, of the total
1999 budget.
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 or gathering systems. 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, raw NGLs are
extracted and the remaining dry gas is treated to meet pipeline quality
specifications ("residue gas" or "gas"). Six of the Company's processing
plants can further separate, or fractionate, the mixed NGL stream into ethane,
propane, normal butane and natural gasoline to obtain a higher value for the
NGLs, and three 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. 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. For a further
discussion of the revenue, operating profit and attributable assets of this
business segment, see "Item 8 - Financial Statements and Supplementary Data."
6
The Company acquires dedicated acreage and natural gas supplies in an effort to
maintain or increase throughput levels to offset natural production declines.
Such natural gas supplies are obtained by purchasing existing systems from third
parties, by connecting additional wells, through internally developed projects
or through joint ventures. Historically, while certain individual plants have
experienced declines in dedicated reserves, the Company has been successful in
connecting additional reserves to more than offset the natural declines. There
has been a reduction in drilling activity, primarily in basins that produce oil
and casinghead gas, from levels that existed in prior years. However, higher
gas prices in 1997 and 1998 (relative to 1995 and 1994), improved technology
(e.g., 3-D seismic and horizontal drilling) and increased pipeline capacity from
the Rocky Mountain region have stimulated drilling in the Powder River Basin and
Southwest Wyoming. Company-wide, the level of drilling will depend upon, among
other factors, the prices for gas and oil, the drilling budgets of third-party
producers, the energy policy of the federal government and the availability of
foreign oil and gas, none of which are within the Company's control. There can
be no assurance that the Company will continue to be successful in replacing the
dedicated reserves processed at its facilities. In 1998, including the reserves
associated with the Company's joint ventures and partnerships and excluding the
facilities sold during the year, the Company connected new reserves to its
gathering systems to replace approximately 86% of 1998 production. On a
Company-wide basis, primarily as a result of the sale of the Perkins and
Edgewood facilities and a downward revision in the reserves associated with the
Bethel facility, dedicated reserves decreased from approximately 3.3 Tcf as of
December 31, 1997 to approximately 3.1 Tcf at December 31, 1998.
Substantially all gas flowing through the Company's facilities is supplied under
long-term contracts providing for the purchase, treating or processing of
natural gas for periods ranging from five to twenty years, using three basic
contract types. Approximately 70% of the Company's plant facilities' gross
margin (revenues at the plants less product purchases) for the year ended
December 31, 1998 resulted from percentage-of-proceeds agreements in which the
Company is typically responsible for arranging for the transportation and
marketing of the gas and NGLs. The price paid to producers is a specified
percentage of the net proceeds received from the sale of the gas and the NGLs.
This type of contract permits the Company and the producers to share
proportionally in price changes.
Approximately 20% of the Company's plant facilities' gross margin for the year
ended December 31, 1998 resulted from contracts that are primarily fee-based
whereby the Company receives a set fee for each Mcf of gas gathered and/or
processed. This type of contract provides the Company with a steady revenue
stream that is not dependent on commodity prices, except to the extent that low
prices may cause a producer to curtail production. The proportion of fee-based
contracts is expected to increase as the volumes from the Powder River coal bed
methane development and Southwest Wyoming increase. See further discussion in
"-Significant Acquisitions, Projects and Dispositions."
Approximately 10% of the Company's plant facilities' gross margin for the year
ended December 31, 1998 resulted from contracts that combine gathering,
compression or processing fees with "keepwhole" arrangements or wellhead
purchases. Typically, producers are charged a gathering and compression fee
based upon volume. In addition, the Company retains a predetermined percentage
of the NGLs recovered by the processing facility and keeps the producers whole
by returning to the producers at the tailgate of the plant an amount of residue
gas equal on a Btu basis to the natural gas received at the plant inlet. The
"keepwhole" component of the contracts permits the Company to benefit when the
value of the NGLs is greater as a liquid than as a portion of the residue gas
stream. However, when the value of the NGLs is lower as a liquid than as a
portion of the residue gas stream, the Company will be adversely affected.
Transmission
The Company owns and operates MIGC, an interstate pipeline located in the Powder
River Basin in Wyoming, and MGTC, an intrastate pipeline located in Northeast
Wyoming. As of December 31, 1998, MIGC charges a FERC approved tariff and is
connected to the Colorado Interstate Gas Pipeline, the Williston Basin
Interstate Pipeline and the Pony Express Pipeline. During July 1998, MIGC
received approval from the FERC to increase its pipeline capacity from 90 MMcf
per day to 130 MMcf per day. The first two compressors associated with this
expansion began operating in December 1998 and the third compressor in the first
quarter of 1999. See further discussion in "-Significant Acquisitions, Projects
and Dispositions," and for a further discussion of the revenue, operating profit
and attributable assets of this business segment, see "Item 8-Financial
Statements and Supplementary Data."
Significant Acquisitions, Projects and Dispositions
The Company's significant acquisitions, projects and dispositions since January
1, 1996 are:
7
Coal Bed Methane
The Company is expanding its Powder River Basin coal bed methane natural gas
gathering system and developing its own coal seam gas reserves in Wyoming. The
Company has acquired drilling rights in the vicinity of known coal bed methane
production. The Company and other operators in the area have established
production from wells drilled to depths of 400 to 1,200 feet. The typical
drilling, completion and gathering costs associated with such activities have
approximated $65,000 per well. As deeper wells are drilled, the average cost
per well is expected to increase. Production from the Powder River coal bed
methane play has been expanding, and the Company estimates that approximately
110 MMcf per day of gas volumes are currently being produced from several
operators in the area, including the Company's interest. Most of the coal bed
methane gas is being transported by MIGC for redelivery to gas markets in the
Rocky Mountain and Midwest regions of the United States. The Company's capital
budget in this area provides for expenditures of approximately $35.8 million
during 1999. This capital budget includes approximately $18.5 million for
drilling costs, production equipment and undeveloped acreage, $15.3 million for
compression and $2 million for the Company's investment in the Fort Union Gas
Gathering, L.L.C., as described below. Depending upon future drilling success,
additional capital expenditures may be required to continue expansion in this
basin. However, because of drilling and other uncertainties beyond the
Company's control, there can be no assurance that this level of capital
expenditure will be incurred or that additional capital expenditures will be
made. During the years ended December 31, 1998 and 1997, the Company had
expended approximately $46.7 million and $32.2 million, respectively, on this
project.
In October 1997, the Company sold a 50% undivided interest in its Powder River
Basin coal bed methane gas operations to Barrett Resources Corporation
("Barrett"). This sale provided the Company with a substantial acreage
dedication for gathering and compression services within an area of mutual
interest ("AMI"), additional man-power resources to accelerate development in
this area and more technical expertise in exploration and production. The sale
involved gathering assets, producing properties, production equipment and
certain undeveloped acreage in this area. The final adjusted purchase price was
$17.9 million, resulting in a pre-tax gain of $4.7 million, which was recognized
in the fourth quarter of 1997.
The AMI with Barrett encompasses approximately 2.1 million acres in the Powder
River coal bed methane play. Both parties will continue to develop certain
specified areas within the AMI, with Barrett becoming the operator of the
producing wells on July 1, 1999. The Company has committed to gather and
compress for a fee, all gas produced from the jointly-owned properties within
the AMI under a long-term agreement.
In December 1998, the Company joined with other industry participants to form
Fort Union Gas Gathering, L.L.C., which plans to build a 106-mile, 24-inch
gathering header to gather coal bed methane in the Powder River Basin in
northeast Wyoming. The Company will have an approximate 13% interest and be the
construction contractor and field operator of the header and a related gas
treating facility. The new gathering header is expected to have an initial
capacity of approximately 450 MMcf per day of natural gas with expansion
capability. The header will deliver coal bed methane gas to a treating facility
to be constructed near Glenrock, Wyoming and will access interstate pipelines to
gas markets in the Rocky Mountain and Midwest regions of the United States.
Construction is scheduled to begin in April 1999 with operations anticipated to
commence on or about the end of the third quarter of 1999. It is anticipated
that the new gathering header and treating system will be project-financed,
requiring a cash investment by the Company of approximately $2 million.
Southwest Wyoming
The Company's facilities in Southwest Wyoming are comprised of the Granger
facility and a 72% ownership interest in the Lincoln Road facility (collectively
the "Granger Complex"). These facilities have a combined operational capacity
of 225 MMcf per day and in the year ended December 31, 1998 processed an average
of 183 MMcf per day. The Granger Complex processes gas produced in the prolific
Greater Green River Basin. Despite the low commodity prices experienced in
1998, drilling activity in this area remained at a high level, as 65 new wells
were connected to these facilities. The Company believes that as governmental
drilling restrictions affecting a portion of this basin are removed in the
fourth quarter of 1999, the Company may have the opportunity to expand these
facilities in the year 2000. The Company's capital budget in this area provides
for expenditures of approximately $14.5 million during 1999. This capital
budget includes approximately $6.1 million for drilling costs and production
equipment and approximately $8.4 million related to gathering, transportation
and expansion of the Granger facility. Because of drilling and other
uncertainties beyond the Company's control, there can be no assurance that this
level of capital expenditure will be incurred or that future capital
expenditures will be made. During the years ended December 31, 1998 and 1997,
the Company has expended approximately $16.0 million and $6.2 million,
respectively, on this project.
In 1997, the Company entered into an agreement with Ultra Resources, Inc.
("Ultra") to participate in the exploration, development, gathering and
processing in the Hoback Basin in Southwestern Wyoming. Under the agreement, a
1.8 million acre AMI was established, in which Ultra currently controls
approximately 350,000 acres. The Company has the option to participate in
exploration and production activities within the AMI for approximately a
15% working interest. The Company and Ultra have also entered into
8
agreements for the gathering and processing of natural gas, which is developed
on 16 prospects within the AMI, through the Company's Granger facility.
Additionally, the Company entered into two separate agreements with RIS
Resources (USA) Inc. ("RIS"), an affiliate of Ultra, to sell RIS undivided
interests in certain assets. Under the first agreement, in February 1998, the
Company sold RIS a 50% undivided interest in a small portion of the Granger
gathering system servicing the Ultra AMI for approximately $4.0 million. This
amount approximated the Company's cost in such facilities. RIS and the Company
expect to install jointly additional gathering assets in this area as needed.
Under the second agreement with RIS, the Company granted RIS the option to
purchase up to 50% of the Granger Complex. In conjunction with this agreement,
in February 1998, RIS paid a $1 million non-refundable option payment to the
Company. RIS's option to acquire an interest in these facilities expired in the
fourth quarter of 1998.
Bethel Treating Facility
In 1996 and 1997 the Pinnacle Reef trend was rapidly developing into a very
active lease acquisition and exploratory play using 3-D seismic technology. The
initial discoveries in the play indicated a very large potential gas
development. Based on the Company's receipt of large acreage dedications in this
area, the Company constructed the Bethel Treating facility for a total cost of
approximately $102.8 million with a throughput capacity of 350 MMcf per day.
In 1998, the production rates from the wells drilled in this field and the
recoverable reserves from these properties, were far less than originally
expected by the producers. As a result, in 1998, the Bethel Treating facility
averaged gas throughput of approximately 61 MMcf per day. Due to the unexpected
poor drilling results and reductions in the producers' drilling budgets, the
number of rigs active in this area has decreased from 18 in July 1998 to one
active rig in March 1999.
Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of"
("SFAS No. 121"), requires that long-lived assets be reviewed whenever events or
changes in circumstances indicate that the carrying value of such assets may
not be recoverable. SFAS No.121 also requires that an impairment loss be
recognized when the carrying amount of an asset exceeds its fair market value or
its expected future undiscounted net cash flows. Because of uncertainties
related to the pace and success of third-party drilling programs, declines in
volumes produced at certain wells and other conditions outside the Company's
control, the Company determined that such an evaluation of the Bethel Treating
facility was necessary. The Company compared the net book value of the assets to
the discounted expected future cash flows of the facility and determined a pre-
tax, non-cash impairment charge of $77.8 million in the fourth quarter of 1998
was required.
Edgewood
In two transactions which closed in October 1998 the Company sold its Edgewood
gathering system, including its undivided interest in the producing properties
associated with this facility, and its 50% interest in the Redman Smackover
Joint Venture ("Redman Smackover"). The combined sales price was $55.8 million.
The proceeds from these sales were used to repay a portion of the balances
outstanding under the Revolving Credit Facility. After the accrual of certain
related expenses, the Company recognized a pre-tax gain of approximately $1.6
million during the fourth quarter of 1998.
Perkins
In November 1997, the Company entered into an agreement to sell its Perkins
Facility. In March 1998, the Company completed the sale of this facility, with
an effective date of January 1, 1998. The sales price was $22.0 million and
resulted in a pre-tax gain of approximately $14.9 million. The proceeds from
this sale were used to repay a portion of the balances outstanding under the
Revolving Credit Facility.
Giddings
In March 1999, the Company entered into an agreement to sell its Giddings
Facility for $36.0 million, which will result in an approximate pre-tax loss
of $4.8 million. This agreement is subject to various approvals and is
anticipated to close in the second quarter of 1999.
9
Katy
The Company continues to view access to storage capacity as a significant
element of its marketing strategy. However, as a result of an increase in
third-party storage services available in the marketplace combined with the
Company's 1999 business plan objective of improving its balance sheet, the
Company entered into an agreement in March 1999 to sell all the outstanding
common stock of its wholly-owned subsidiary, Western Gas Resources Storage,
Inc., for $100.0 million. This transaction will result in an approximate
pre-tax loss of $18.5 million. The only asset of this subsidiary is the Katy
Facility. This agreement is subject to various regulatory approvals and the
satisfaction of certain contractual conditions and is anticipated to close in
the second quarter of 1999. The Company has the option to sell approximately 5.4
Bcf of stored gas in the Katy Facility to the same purchaser for total sales
proceeds of approximately $10.0 million (which would approximate its cost of the
inventory). To meet the needs of its marketing operations, the Company will
continue to contract for storage capacity. Accordingly, the Company will enter
into a long-term agreement with the purchaser for approximately 3 Bcf of storage
capacity at market rates.
Other
The Company routinely reviews 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 or third party-owned facilities,
dismantlement, asset swap or outright sale.
MARKETING
Gas
The Company markets gas produced at its plants and purchased from third parties
to end-users, local distribution companies ("LDCs"), pipelines and other
marketing companies throughout the United States and in Canada. Historically,
the Company's gas marketing was an outgrowth of the Company's gas processing
activities and was directed towards selling gas processed at its plants to
ensure their efficient operation. As the Company expanded into new basins and
the natural gas industry became deregulated and offered more opportunity, the
Company began to increase its third-party gas marketing. For the year ended
December 31, 1998, the Company's gas sales volumes averaged 2.2 Bcf per day.
Third-party sales and gas storage, combined with the stable supply of gas from
the Company's facilities, enable the Company to respond quickly to changing
market conditions and to take advantage of seasonal price variations and peak
demand periods. The Company sells gas under agreements with varying terms and
conditions in order to match seasonal and other changes in demand. Most of the
Company's current sales contracts range from a few days to two years.
In general, the Company does not expect to increase its third-party sales
volumes significantly from levels achieved during the year ended December 31,
1998. The Company's 1999 gas marketing plan emphasizes growth through its asset
base and storage and transportation capacities which it controls. During 1997,
the Company created a wholly-owned subsidiary to operate a marketing office in
Calgary, Alberta. The Calgary office provides the Company with information
regarding gas supplies being transported from Canada and establishes a presence
in an evolving gas market.
The Company continues to view access to storage capacity as a significant
element of its marketing strategy. The Company customarily stores gas in
underground storage facilities to ensure an adequate supply for long-term sales
contracts and for resale during periods when prices are favorable. As of
December 31, 1998, the Company had contracts in place for approximately 16.2 Bcf
of storage capacity, including storage through its Canadian subsidiary, for
resale during periods when prices are favorable. The fees associated with such
contracts currently do not exceed $.61 per Mcf and the associated periods range
from two months to six years. As of December 31, 1998, the Company also had
contracts for approximately 490 MMcf per day of firm transportation;
approximately 30% of such contracts expire during 1999. The fees associated with
such contracts do not exceed $.33 per Mcf, and the associated periods range from
seven months to thirteen years. Certain of these long-term storage and firm
transportation contracts require an annual renewal. In addition, certain
contracts contain provisions which would require the Company to pay the fees
associated with such contracts whether or not the service was used.
The Company held gas in storage and held imbalances of approximately 19.9 Bcf at
an average cost of $2.13 per Mcf at December 31, 1998 compared to 6.0 Bcf at an
average cost of $1.97 per Mcf at December 31, 1997, at various storage
facilities, including the Katy Facility. At December 31, 1998, the Company had
hedging contracts in place for anticipated sales of approximately 18.6 Bcf of
stored gas at a weighted average price of $2.41 per Mcf for the stored
inventory. See further discussion in "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Liquidity and Capital Resources
- - Risk Management Activities."
During the year ended December 31, 1998, the Company sold gas to approximately
475 end-users, pipelines, LDCs and other customers. No single gas customer
accounted for more than 4% of consolidated revenues for the year ended December
31, 1998.
10
NGLs
The Company markets NGLs (ethane, propane, iso-butane, normal butane, natural
gasoline and condensate), produced at its plants and purchased from third
parties, in the Rocky Mountain, Mid-Continent, Gulf Coast and Southwestern
regions of the United States. A majority of the Company's production of NGLs
moves to the Gulf Coast area, which is the largest NGL market in the United
States. Through the development of end-use markets and distribution
capabilities, the Company seeks to ensure that products from its plants move on
a reliable basis, avoiding curtailment of production. For the year ended
December 31, 1998, NGL sales averaged 4,730 MGal per day, an increase from 2,941
MGal per day in 1993, primarily due to the increase in third-party sales,
acquisitions and facility expansions during the five-year period.
Consumers of NGLs are primarily the petrochemical industry, the petroleum
refining industry and the retail and industrial fuel markets. As an example, the
petrochemical industry uses ethane, propane, normal butane and natural gasoline
as feedstocks in the production of ethylene, which is used in the production of
various plastics products. Over the last several years, the petrochemical
industry has increased its use of NGLs as a major feedstock and is projected to
continue to increase such usage. Further, propane is used for home heating,
transportation and for certain agricultural applications. Demand for NGLs is
primarily affected by price, seasonality and the economy.
The Company increased sales to third parties by approximately 385 MGal per day
for the year ended December 31, 1998 compared to 1997. In general, the Company
does not anticipate that sales to third parties in 1999 will increase at the
rate experienced in prior years. The Company's NGL marketing plan contemplates:
(i) continued growth in sales to end-users; (ii) maximizing profitability on
volumes produced at the Company's facilities; and (iii) efficient use of various
third-party storage facilities to increase profitability while limiting carrying
risk.
The Company leases NGL storage space at major trading locations, primarily near
Houston and in central Kansas, in order to store products for resale during
periods when prices are favorable and to facilitate the distribution of
products. In addition, as of December 31, 1998, the Company had contracts in
place for approximately 30,450 MGal of storage capacity. The base fees
associated with such contracts currently do not exceed $.03 per gallon and the
associated periods range from three months to four years. Certain of the long-
term contracts require an annual renewal and contain provisions which would
require the Company to pay the fees associated with such contracts whether or
not the service was used.
The Company held NGLs in storage of 16,900 MGal, consisting primarily of propane
and normal butane, at an average cost of $.24 per gallon and 14,400 MGal at an
average cost of $.37 per gallon at December 31, 1998 and 1997, respectively, at
various third-party storage facilities. At December 31, 1998, the Company had no
significant hedging contracts in place for anticipated sales of stored NGLs. The
Company generally intends that stored NGLs turn over on an annual basis.
NGL sales were made to approximately 175 different customers and no single
customer accounted for more than 2% of the Company's consolidated revenues for
the year ended December 31, 1998. Revenues are also derived from contractual
marketing fees charged to some producers for NGL marketing services. For the
year ended December 31, 1998, 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 allowed
companies to participate in a market previously controlled by electric
utilities. During 1996 and 1997, the Company traded electric power in the
wholesale market and entered into transactions that arbitraged the value of gas
and electric power. During the second half of 1997, the Company elected to
discontinue wholesale trading of electric power, due to a lack of profitability.
For a further discussion of the revenue, operating profit and attributable
assets of the Marketing segment, see "Item 8 -Financial Statements and
Supplementary Data."
PRODUCING PROPERTIES
During 1997, the Company began to invest more capital in oil and gas producing
activities primarily to replace declining reserves which are processed at the
Company's facilities and to encourage expansion in basins where the Company's
facilities are located. See "Business and Properties - Significant Acquisitions,
Projects and Dispositions - Coal Bed Methane and -Southwest Wyoming". The
Company believes that in order to secure additional gas supply for its
facilities, it must be willing to consider its participation
11
in exploration and production activities. Revenues derived from the Company's
producing properties comprised approximately 1.3%, 1.3% and 1.6% of consolidated
revenues, respectively, for the years ended December 31, 1998, 1997 and 1996.
For a further discussion of the revenue, operating profit and attributable
assets of this business segment, see "Item 8 - Financial Statements and
Supplementary Data."
The net annual production volumes are summarized as follows:
December 31,
-------------------------------------------------
1998 1997 1996
--------------- --------------- ---------------
Gas Oil Gas Oil Gas Oil
State (MMcf) (MBbl) (MMcf) (MBbl) (MMcf) (MBbl)
- ------------------------- ------- ------ ------- ------ ------- ------
Colorado................. 274 2 243 6 73 6
Louisiana................ 2,810 75 4,760 108 7,255 117
Texas (1)................ 1,787 5 6,092 21 7,193 32
Wyoming:
Coal Bed Methane....... 7,136 - 1,751 - 12 -
All Other.............. 3,283 40 1,752 19 233 3
------ ---- ------ --- ------ ---
Total.................... 15,290 122 14,598 154 14,766 158
====== ==== ====== === ====== ===
(1) The Company sold its producing properties in Texas during 1998.
As a result of a review of the reserves at the Company's Black Lake facility,
and by comparing the net book value of the assets to the undiscounted expected
future cash flows, determined by applying future prices estimated by management
over the lives of the associated reserves, the Black Lake reserves and the
processing facility associated with such reserves were written down in
accordance with SFAS No. 121 to the net present value of expected cash flows
discounted using an interest rate commensurate with the risk associated with the
underlying asset. Accordingly, the Company recognized a pre-tax, non-cash loss
of $28.8 million for the year ended December 31, 1998. In addition, the Company
recognized a pre-tax, non-cash loss on the impairment of property and equipment,
primarily related to its Black Lake facility and Sand Wash Basin assets, of
$34.6 million for the year ended December 31, 1997.
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, treating
and marketing businesses both for supplies of natural gas and for customers for
its gas and NGLs. Competition for natural gas supplies is primarily based on a
processors' efficiency and reliability in providing services, and in the
availability of transportation to market centers to obtain a satisfactory price
for the producers' natural gas. Competition for customers is primarily based
upon reliability and the market price of deliverable gas and NGLs. For customers
that have the capability of using alternative fuels, such as oil and coal, the
Company also competes primarily on the basis of price against companies capable
of providing such alternative fuels. The Company's competitors for obtaining
additional natural gas supplies, for gathering and processing natural gas and
for marketing gas and NGLs include national and local gas gatherers, brokers,
marketers and distributors of various sizes, financial resources and experience.
REGULATION
The purchase and sale of natural gas and the fees received for gathering and
processing by the Company have generally not been subject to regulation and,
therefore, except as constrained by competitive factors, the Company has
considerable pricing flexibility.
12
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 services necessary to enable the
Company to make deliveries and/or sales of gas can at times be pre-empted by
other system users in accordance with FERC-approved methods for allocating the
system capacity of "open access" pipelines. Moreover, the rates charged by
pipelines for such services are often subject to negotiation between shippers
and the pipelines within certain FERC-established parameters and will
periodically vary depending upon individual system usage and other factors. An
inability to obtain transportation and/or storage services at competitive rates
can hinder the Company's processing and marketing operations and/or adversely
affect its sales margins.
In 1997, the State of Texas adopted a statute that will require the Company to
obtain a pre-construction permit for certain gas gathering lines containing more
than 100 parts per million of hydrogen sulfide and grants affected persons, in
certain circumstances, the right to request a hearing relating to the issuance
of such a permit. This may increase the time and cost associated with
constructing hydrogen sulfide gathering lines. The Company operates the MiVida
and the Bethel facilities in Texas which removes hydrogen sulfide from
the natural gas.
Generally, gathering and processing prices are not regulated by the FERC or any
state agency. However, in May 1995, the Oklahoma Corporation Commission (the
"OCC") was granted limited authority in certain circumstances, after the filing
of a complaint by a producer, to compel a gas gatherer to provide open access
gathering and to set aside unduly discriminatory gathering fees. The Oklahoma
state legislature is considering legislation that would expand the authority of
the OCC to compel a gas gatherer to provide open access gas gathering and to
establish rates, terms and conditions of services provided by a gas gatherer. In
addition, the state legislatures and regulators in certain other states in which
the Company gathers gas are also contemplating additional regulation of gas
gathering. The Company does not believe that any of the proposed legislation of
which it is aware is likely to have a material adverse effect on the Company's
financial position or results of operation. However, the Company cannot predict
what additional legislation or regulations the States may adopt regarding gas
gathering.
EMPLOYEES
At December 31, 1998, the Company employed approximately 870 full-time
employees, none of whom was a union member. The Company considers relations with
employees to be excellent.
ITEM 3. LEGAL PROCEEDINGS
Reference is made to Note 8 of the Company's Consolidated Financial Statements
in Item 8 of this Form 10-K.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the quarter
ended December 31, 1998.
13
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
As of March 15, 1999, there were 32,147,993 shares of Common Stock outstanding
held by 321 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
--------- ---------
1998
Fourth Quarter..................... $ 9 7/8 $ 5 5/16
Third Quarter...................... 15 1/8 8
Second Quarter..................... 19 5/8 13 7/8
First Quarter...................... 22 1/8 15 7/8
1997
Fourth Quarter..................... 25 9/16 20
Third Quarter...................... 22 1/2 16 3/4
Second Quarter..................... 20 1/2 14 7/8
First Quarter...................... $21 3/8 $17 3/4
The Company paid annual dividends on the Common Stock aggregating $.20 per share
during the years ended December 31, 1998 and 1997. The Company has declared a
dividend of $.05 per share of Common Stock for the quarter ending March 31, 1999
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 that exceed, in the aggregate, the sum of $50 million plus 50%
of the Company's consolidated net income earned after June 30, 1995 (or minus
100% if a net loss), plus the aggregate net cash proceeds received after June
30, 1995 from the sale of any stock. At December 31, 1998, availability under
this covenant amounted to $51.5 million. This amount is expected to be reduced
by approximately $14.9 million as a result of the after-tax losses recognized on
the sales of the Giddings and Katy facilities.
14
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected consolidated financial and operating
data for the Company. Certain prior year amounts have been reclassified to
conform to the presentation used in 1998. The data for the years ended December
31, 1998, 1997 and 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 years ended December 31, 1995 and
1994 is derived from the Company's audited historical Consolidated Financial
Statements. See also Item 7 - "Management's Discussion and Analysis of Financial
Condition and Results of Operations."
Year Ended December 31,
--------------------------------------------------------------------------------------
1998 1997 1996 1995 1994
-------------- --------------- -------------- ---------------- ----------
(000s, except per share amounts and operating data)
STATEMENT OF OPERATIONS:
Revenues.............................. $2,133,566 $ 2,385,260 $2,091,009 $1,256,984 $1,063,489
Gross profit (a)...................... 66,568 93,755 105,479 75,211 72,556
Income (loss) before income taxes..... (105,623) (b) 2,220 (b) 41,631 (8,266) (c) 11,524
Provision (benefit) for income taxes.. (38,418) 733 13,690 (2,158) 4,160
Net income (loss)..................... (67,205) (b) 1,487 (b) 27,941 (6,108) (c) 7,364
Earnings (loss) per share of
common stock......................... (2.42) (.28) .66 (.84) (.19)
Earnings (loss) per share of
common stock - assuming dilution..... (2.42) (.28) .66 (.84) (.19)
CASH FLOW DATA:
Net cash provided by operating
activities........................... (35,570) 114,755 168,266 86,373 31,866
Capital expenditures.................. 105,216 198,901 74,555 78,521 100,540
BALANCE SHEET DATA
(at year end):
Total assets.......................... 1,219,377 1,348,276 1,361,631 1,193,997 1,167,362
Long-term debt........................ 504,881 441,357 379,500 529,500 493,000
Stockholders' equity.................. 385,216 468,112 480,467 371,909 436,683
Dividends declared per share of
common stock......................... $ .20 $ .20 $ .20 $ .20 $ .20
OPERATING DATA:
Average gas sales (MMcf/D)............ 2,200 1,975 1,794 1,572 1,097
Average NGL sales (MGal/D)............ 4,730 4,585 3,744 2,890 2,970
Average gas volumes
gathered (MMcf/D).................... 1,162 1,229 1,171 1,020 934
Facility capacity (MMcf/D)............ 2,237 2,302 1,940 1,907 1,560
Average gas prices ($/Mcf)............ $ 2.01 $ 2.30 $ 2.19 $ 1.53 $ 1.77
Average NGL prices ($/Gal)............ $ .26 $ .36 $ .41 $ .31 $ .28
_________________________________________
(a) Excludes selling and administrative, interest, restructuring and income tax
expenses and loss on the impairment of property and equipment. See further
discussion in notes (b) and (c).
(b) SFAS No. 121 requires that an impairment loss be recognized when the
carrying amount of an asset exceeds the fair market value of or the expected
future undiscounted net cash flows. In accordance with SFAS No. 121, the
Company recognized a pre-tax, non-cash loss on the impairment of property
and equipment of $108.5 million, ($69.0 million, after-tax) and $34.6
million, pre-tax, ($22.0 million, after-tax) for the years ended December
31, 1998 and 1997, respectively.
(c) In accordance with SFAS No. 121, the Company recognized a pre-tax, non-cash
loss for the year ended December 31, 1995 on the impairment of property and
equipment of $17.6 million, and $12.4 million, after-tax. Also, the Company
implemented a cost reduction program to reduce operating and selling and
administrative expenses. As a result of this program, a $2.1 million, pre-
tax, and $1.3 million, after-tax, restructuring charge was incurred,
primarily related to employee severance costs.
15
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion and analysis relates to factors that have affected the
consolidated financial condition and results of operations of the Company for
the three years ended December 31, 1998. Certain prior year amounts have been
reclassified to conform to the presentation used in 1998. 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, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
(000S, EXCEPT PER SHARE AMOUNTS AND OPERATING DATA)
Year Ended
December 31, Percent
-------------------------
1998 1997 Change
------------- ---------- -------
FINANCIAL RESULTS:
Revenues............................................ $2,133,566 $2,385,260 (11)
Gross profit........................................ 66,568 93,775 (29)
Net income (loss)................................... (67,205) 1,487 -
Loss per share of common stock...................... (2.42) (.28) (764)
Loss per share of common stock - assuming dilution.. (2.42) (.28) (764)
Net cash provided by (used in) operating activities. $ (35,570) $ 114,755 -
OPERATING DATA:
Average gas sales (MMcf/D).......................... 2,200 1,975 11
Average NGL sales (MGal/D).......................... 4,730 4,585 3
Average gas prices ($/Mcf).......................... $ 2.01 $ 2.30 (13)
Average NGL prices ($/Gal).......................... $ .26 $ .36 (28)
Net income decreased $68.7 million for the year ended December 31, 1998 compared
to 1997. The decrease in net income for the year was primarily due to a $69.0
million, after-tax, charge for impairment recorded in connection with the
evaluation of a decrease in product prices and the impact on the Company's
Bethel, Black Lake and Sand Dunes facilities, as required by SFAS No. 121.
Revenues from the sale of gas decreased approximately $46.0 million for the year
ended December 31, 1998 compared to 1997. Average gas sales volumes increased
225 MMcf per day to 2,200 MMcf per day for the year ended December 31, 1998
compared to 1997, primarily due to an increase in the sale of gas purchased from
third parties. The increase in volumes sold was more than offset by a decrease
in average gas prices. Average gas prices realized by the Company decreased $.29
per Mcf to $2.01 per Mcf for the year ended December 31, 1998 compared to 1997.
Included in the realized gas price is approximately $71,000 of loss recognized
in the year ended December 31, 1998 related to futures positions on equity
volumes. The Company has entered into futures positions for a portion of its
equity gas for 1999 and 2000. See further discussion in "Liquidity and Capital
Resources - Risk Management."
Revenues from the sale of NGLs decreased approximately $162.3 million for the
year ended December 31, 1998 compared to 1997. Average NGL sales volumes
increased 145 MGal per day to 4,730 MGal per day for the year ended December 31,
1998 compared to 1997, primarily due to an increase in the sale of NGLs
purchased from third parties. The increase in sales volumes was more than offset
by a decrease in average NGL prices. Average NGL prices realized by the Company
decreased $.10 per gallon to $.26 per gallon for the year ended December 31,
1998 compared to 1997. Included in the realized NGL price was approximately $7.4
million of gain recognized in the year ended December 31, 1998 related to
futures positions on equity volumes. The Company has entered into futures
positions for a portion of its equity production for 1999. See further
discussion in "-Liquidity and Capital Resources - Risk Management."
Revenue associated with electric power marketing decreased approximately $59.5
million for the year ended December 31, 1998 compared to 1997, as the Company
discontinued wholesale trading of electric power in 1997, due to a lack of
profitability.
16
Other net revenue increased approximately $12.2 million for the year ended
December 31, 1998 compared to 1997. The increase was primarily due to a $14.9
million gain on the sale of the Company's Perkins facility and a $1.0 million
option payment received from RIS in connection with the potential sale of a
portion of certain of the Company's assets in Southwest Wyoming. These increases
were offset by decreases of approximately $2.8 million in earnings from the
Company's investments in joint ventures, primarily due to the decreases in
product prices and the sale of its interest in Redman Smackover. See further
discussion at "Business and Properties - Significant Acquisitions, Projects and
Dispositions - Southwest Wyoming and Significant Acquisitions, Projects and
Dispositions - Redman Smackover Joint Venture."
The reduction in product purchases of $232.1 million to $1.9 billion for the
year ended December 31, 1998 compared to 1997, was primarily due to a decrease
in commodity prices. Overall, combined product purchases as a percentage of
sales of all products increased from 92% to 93% for the year ended December 31,
1998 compared to 1997. Over the past several years, the Company has experienced
narrowing margins in its third-party sales as a result of increasing
competitiveness of the natural gas marketing industry. During the year ended
December 31, 1998, margins on the sale of third-party gas declined and averaged
approximately $.02 per Mcf compared to approximately $.03 per Mcf for 1997.
Contributing to the increase in the product purchase percentage for the year
ended December 31, 1998 were higher payments related to the Company's
"keepwhole" contracts at its Granger facility. Under a "keepwhole" contract, the
Company's margin is reduced when the value of NGLs declines relative to the
value of gas. Also included in product purchases were lower of cost or market
writedowns, primarily related to NGL inventories, of $826,000 and $1.1 million
for the years ended December 31, 1998 and 1997, respectively.
Plant operating expense increased approximately $7.2 million for the year ended
December 31, 1998 compared to 1997. The increase was primarily due to
compression costs associated with the increasing Powder River Basin coal bed
methane production activities and expenses incurred at the Bethel Treating
facility, which became partially operational during the third quarter of 1997.
Interest expense increased $6.1 million for the year ended December 31, 1998
compared to 1997. The increase is the result of less interest capitalized to
capital projects, primarily the Bethel Treating facility, and larger debt
balances outstanding during the year ended December 31, 1998 compared to 1997.
The larger debt balances resulted primarily from higher product inventory
positions, capital expenditures associated with the Bethel Treating facility and
reduced cashflow from operations.
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
(000S, EXCEPT PER SHARE AMOUNTS AND OPERATING DATA)
Year Ended
December 31, Percent
-------------------------
1997 1996 Change
------------- ---------- -------
FINANCIAL RESULTS:
Revenues....................................................... $2,385,260 $2,091,009 14
Gross profit................................................... 93,775 105,479 (11)
Net income..................................................... 1,487 27,941 (95)
Earnings (loss) per share of common stock...................... (.28) .66 -
Earnings (loss) per share of common stock - assuming dilution.. (.28) .66 -
Net cash provided by operating activities...................... $ 114,755 $ 168,266 (32)
OPERATING DATA:
Average gas sales (MMcf/D)..................................... 1,975 1,794 10
Average NGL sales (MGal/D)..................................... 4,585 3,744 22
Average gas prices ($/Mcf)..................................... $ 2.30 $ 2.19 5
Average NGL prices ($/Gal)..................................... $ .36 $ .41 (12)
Net income decreased $26.5 million for the year ended December 31, 1997 compared
to 1996. The decrease in net income for the year was primarily due to a $22.0
million, after-tax, impairment loss recorded in connection with the evaluation
of certain property and equipment, primarily related to its Black Lake facility
and Sand Wash Basin assets, as required by SFAS No.121. Net income in 1997
increased by a $3.0 million after-tax gain associated with the sale of a 50%
interest in the Company's coal bed methane operations.
Revenues from the sale of gas increased approximately $216.6 million for the
year ended December 31, 1997 compared
17
to 1996. Average gas sales volumes increased 181 MMcf per day to 1,975 MMcf per
day for the year ended December 31, 1997 compared to 1996, primarily due to an
increase in the sale of gas purchased from third parties. Average gas prices
realized by the Company increased $.11 per Mcf to $2.30 per Mcf for the year
ended December 31, 1997 compared to 1996. Included in the realized gas price was
approximately $5.6 million of loss recognized in the year ended December 31,
1997 related to futures positions on equity volumes.
Revenues from the sale of NGLs increased approximately $50.4 million for the
year ended December 31, 1997 compared to 1996. Average NGL sales volumes
increased 841 MGal per day to 4,585 MGal per day for the year ended December 31,
1997 compared to 1996, largely due to an increase of approximately 800 MGal per
day in the sale of NGLs purchased from third parties. Average NGL prices
realized by the Company decreased $.05 per gallon to $.36 per gallon for the
year ended December 31, 1997 compared to 1996. Included in the realized NGL
price was approximately $5.2 million of gain recognized in the year ended
December 31, 1997 related to futures positions on equity volumes.
Revenue associated with electric power marketing increased $28.8 million for the
year ended December 31, 1997 compared to 1996, primarily because the Company had
minimal transactions in this market during 1996. Due to a lack of profitability,
the Company elected to discontinue trading electric power and began to evaluate
its role in this emerging business, during the second half of 1997.
The increase in product purchases of $302.3 million to $2.1 billion for the year
ended December 31, 1997 compared to 1996, is primarily a combination of higher
gas prices and increased sales of NGLs purchased from third parties.
Contributing to the increase in product purchases for the year ended December
31, 1997 compared to 1996 were higher payments to producers related to the
Company's "keepwhole" contracts at its Granger facility. Under a "keepwhole"
contract, the Company's margin is reduced when the value of NGLs declines
relative to the value of gas. Also contributing to the increases in product
purchases for the year ended December 31, 1997 compared to 1996, were lower of
cost or market write-downs of NGL and gas inventories of $1.1 million and
$129,000, respectively.
Plant operating expense increased approximately $5.0 million for the year ended
December 31, 1997 compared to 1996. The increase was primarily due to additional
compression cost associated with the MIGC pipeline. In addition, results of
operations for the year ended December 31, 1997 were adversely affected by
additional costs associated with the Bethel Treating facility. As a result of
start-up costs associated with opening the facility and depreciation, the Bethel
Treating facility did not contribute positively to earnings in 1997.
Depreciation, depletion and amortization decreased $4.0 million for the year
ended December 31, 1997 compared to 1996. The decrease was primarily due to
decreases in produced volumes related to the Company's Black Lake facility which
resulted in a decrease in the associated depletion.
Interest expense decreased $7.0 million for the year ended December 31, 1997
compared to 1996. The decrease in interest expense was primarily due to lower
average outstanding debt balances due to the use of the Company's net proceeds
from the November 1996 public offering of 6,325,000 shares of Common Stock to
reduce indebtedness under the Revolving Credit Facility.
Overall, profitability for the year ended December 31, 1997 was less than
anticipated due to several factors. Combined product purchases as a percentage
of all product sales increased from 91% to 92% for the year ended December 31,
1997 compared to 1996. Over the past several years, the Company has experienced
narrowing margins related to the increasing competitiveness of the natural gas
marketing industry. During the year ended December 31, 1997, the Company's
marketing margins were reduced by approximately 50% compared to 1996. Included
in the sale of gas and product purchases for the last half of 1997, is the sale
of approximately 11.5 Bcf of gas, previously stored in the Katy Facility, at a
margin of approximately $.20 per Mcf.
BUSINESS STRATEGY
The Company's long-term, four-part business plan is designed to increase
profitability through: (i) investing in projects that complement and extend its
core gas gathering, processing, production and marketing business; (ii) creating
ventures with producers who dedicate additional acreage to the Company; (iii)
maintaining or expanding its energy sales volumes and margins by maximizing its
asset base, firm transportation and storage contracts and other contractual
arrangements; and (iv) optimizing the profitability of existing operations and
in certain cases, considering the disposal of non-growth assets.
Historically, crude oil prices have been volatile and the oil and gas industry
is currently experiencing ten year lows in these prices. As of March 1, 1999
such prices had declined to approximately $12.25 per barrel. Most NGL value is
tied closely to crude oil, accordingly this pricing environment is having a
detrimental effect on the Company's results of operations.
18
The Company's 1999 plan provides for the improvement of the balance sheet and
liquidity while ensuring the continued development of its two primary growth
projects, the Powder River Basin coal bed methane and Southwest Wyoming
operations. In order to reduce the Company's overall debt level and provide it
with additional liquidity, the Company has signed agreements in March 1999
providing for the sale of its Giddings Gathering System and Katy Facility for
total proceeds of approximately $136 million. These transactions will result in
an after-tax loss in 1999 of approximately $14.9 million and are expected to
close in the second quarter of 1999, subject to various regulatory approvals and
the satisfaction of certain contractual conditions.
Expansion of Core Business
The Company will continue to evaluate 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, producing properties, transportation or storage
assets and NGL product upgrade equipment. In 1999, the Company's capital
expenditures will be reduced compared to levels expended in 1998 and 1997, and
will be concentrated on the Powder River Basin coal bed methane and Southwest
Wyoming operations. Expenditures on these projects are anticipated to comprise
53% and 22%, respectively, of the total 1999 budget. See further discussion in
"Business and Properties -Significant Acquisitions, Projects and Dispositions."
Increase Dedicated Acreage
The Company enters into agreements which provide it with new dedicated acreage
and wells to replace declines in reserves and generate additional volumes for
gathering and processing at its facilities. The Company has increased its
participation in exploration and production activities. Over the past several
years, the Company has attempted to structure its contracts to minimize the
impact of fluctuating NGL prices. This has been accomplished by entering fee
based contracts and minimizing the use of keep-whole contracts. See further
discussion in "Business and Properties - Significant Acquisitions, Projects and
Dispositions."
Maintain or Expand Energy Marketing Services and Volumes
The Company is a full-service marketer of gas and NGL products. The Company
focuses on the individual needs of its customers, primarily in the Rocky
Mountain region, and is committed to developing products and services that are
tailored to meet their requirements. The Company plans to maintain or expand its
energy marketing activities by: (i) maximizing profitability on volumes produced
at the Company's facilities; (ii) efficient use of various firm transportation
and storage contracts and other contractual arrangements to increase
profitability while limiting carrying risk; (iii) continuing to pursue higher-
margin, end-use markets, primarily in the Rocky Mountain region; and (iv)
maintaining third-party gas and NGL sales volumes. The Company believes it
competes effectively with other marketers due to its national marketing presence
and the marketing information gained thereby, the services it provides and its
physical asset base.
Optimize Profitability
The Company seeks to optimize the profitability of its operations by: (i)
maintaining or increasing natural gas throughput levels; (ii) increasing its
efficiency through the consolidation of existing facilities; (iii) investing in
assets that enhance NGL value; (iv) selling non-growth 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.
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. In 1998, sources of liquidity also included the sale of the
Perkins Facility and the Edgewood Facility and related production. Additionally,
the Company entered into agreements in March 1999 for the sale of the Giddings
Facility and the Katy Facility for amounts approximating $136 million in gross
proceeds. These transactions are expected to close in the second quarter of
1999, subject to various regulatory approvals and the satisfaction of certain
contractual conditions. The net proceeds from these sales will be used to reduce
debt. Net cash provided by operating activities is primarily affected by product
prices, 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, the margin on third-party product purchased for resale, as well as
the timely collection of the Company's receivables.
19
The Company's future growth will be dependent upon obtaining additions to
dedicated plant reserves, acquisitions, new project development, marketing,
efficient operation of its facilities and its ability to obtain financing at
favorable terms.
Given the depressed oil and NGL prices the Company has been experiencing and the
disappointing results from the Bethel Treating Facility, the Company sought and
has successfully negotiated amendments to certain covenant requirements in its
various financing facilities and has negotiated amendments to these financing
facilities which are intended to provide more flexibility in a low price
environment. There can be no assurance that further amendments or waivers can be
obtained in the future, if necessary, or that the terms would be favorable to
the Company. To strengthen credit ratings and to reduce its overall debt
outstanding, the Company will continue to dispose of non-strategic assets (such
as the Giddings and Katy facilities) and investigate alternative financing
sources (including project - financing, joint ventures, public debt and
operating leases).
The Company believes that the amounts available to be borrowed under the
Revolving Credit Facility, together with net cash provided by operating
activities and the sale of non-strategic assets, will provide 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
financing facilities, although it may request additional borrowing capacity from
its lenders, seek waivers from its lenders to permit it to borrow funds from
third parties, seek replacement financing facilities from other lenders, use
stock as a currency for an acquisition, sell existing assets or a combination of
such alternatives. While the Company believes that it would be able to secure
additional financing, if required, no assurance can be given that it will be
able to do so or as to the terms of any such financing. Despite the current
depressed oil prices, the Company also believes that cash provided by operating
activities and amounts available under its Revolving Credit Facility will be
sufficient to meet its debt service and preferred stock dividend requirements
for the remainder of 1999.
The Company's sources and uses of funds for the year ended December 31, 1998 are
summarized as follows (000s):
SOURCES OF FUNDS:
Borrowings on Revolving Credit Facility................... $3,230,400
Proceeds from the dispositions of property and equipment.. 78,775
Proceeds from exercise of common stock options............ 23
----------
Total sources of funds.................................. $3,309,198
==========
USES OF FUNDS:
Payments related to long-term debt agreements............. $3,166,920
Capital expenditures...................................... 105,216
Net cash used in operating activities..................... 35,570
Dividends paid............................................ 16,869
----------
Total uses of funds..................................... $3,324,575
==========
Additional sources of liquidity available to the Company are its inventories of
gas and NGLs in storage facilities. The Company stores gas and NGLs primarily to
ensure an adequate supply for long-term sales contracts and for resale during
periods when prices are favorable. The Company held gas in storage and held
imbalances of approximately 19.9 Bcf at an average cost of $2.13 per Mcf at
December 31, 1998 compared to 6.0 Bcf at an average cost of $1.97 per Mcf at
December 31, 1997, at various storage facilities, including the Katy Facility.
At December 31, 1998, the Company had hedging contracts in place for anticipated
sales of approximately 18.6 Bcf of stored gas at a weighted average price of
$2.41 per Mcf for the stored inventory. See "Item 1 and 2 - Business and
Properties - Significant Acquistions, Projects and Dispostions - Katy". The
Company held NGLs in storage of 16,900 MGal, consisting primarily of propane and
normal butane, at an average cost of $.24 per gallon and 14,400 MGal at an
average cost of $.37 per gallon at December 31, 1998 and 1997, respectively, at
various third-party storage facilities. At December 31, 1998, the Company had no
significant hedging contracts in place for anticipated sales of stored NGLs.
Historically, while certain individual plants have experienced declines in
dedicated reserves, the Company has been successful in connecting additional
reserves to more than offset the natural declines. There has been a reduction in
drilling activity, primarily in basins that produce oil and casinghead gas, from
levels that existed in prior years. However, higher gas prices in 1997 and 1998,
improved technology (e.g., 3-D seismic and horizontal drilling) and increased
pipeline capacity from the Rocky Mountain region have stimulated drilling in the
Powder River Basin and Southwest Wyoming. Company-wide, the level of drilling
will depend upon, among other factors, the prices for gas and oil, the drilling
budgets of third-party producers, the energy policy of the federal government
and the availability of foreign oil and gas, none of which are within the
Company's control. There is no assurance that the Company will continue to be
successful in replacing the dedicated reserves processed at its facilities. In
1998, including the reserves associated with the Company's joint ventures and
partnerships and excluding the facilities sold during the year, the Company
connected new reserves
20
to its facilites to replace approximately 86% of 1998 production. On a
Company-wide basis, primarily as a result of the sale of the Edgewood and
Perkins facilities and a downward revision in the reserves associated with the
Bethel Facility, dedicated reserves decreased from approximately 3.3 Tcf as of
December 31, 1997 to approximately 3.1 Tcf at December 31, 1998.
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.
Capital Investment Program
For the years ended December 31, 1998, 1997 and 1996 the Company expended $105.2
million, $198.9 million and $74.6 million, respectively, on new projects and
acquisitions. For the year ended December 31, 1998, the Company's expenditures
consisted of the following: (i) $50.4 million for new connects, system
expansions, the Bethel Treating facility and asset consolidations; (ii) $10.6
million for maintaining existing Facilities; (iii) $41.6 million for exploration
and production activities and acquisitions; and (iv) $2.6 million of
miscellaneous expenditures.
Largely as a result of low commodity prices, primarily affecting NGL products,
the Company has reduced its budget for capital expenditures in 1999 from the
levels expended in 1997 and 1998. Capital expenditures related to existing
operations are expected to be approximately $67.0 million during 1999,
consisting of the following: (i) capital expenditures related to gathering,
processing and pipeline assets are expected to be approximately $39.6 million,
of which $6.3 million is for maintaining existing facilities; (ii) capital
expenditures on exploration and production activities are expected to be
approximately $24.6 million; and (iii) capital expenditures for miscellaneous
items are expected to be approximately $2.8 million. Overall, capital
expenditures in the Powder River Basin coal bed methane development and in
Southwest Wyoming operations represent 53% and 22%, respectively, of the total
1999 budget.
Financing Facilities
Revolving Credit Facility. The Company's variable rate Revolving Credit
Facility was restated and amended in May 1997. The Revolving Credit Facility is
with a syndicate of banks and provides for a maximum borrowing commitment of
$300 million, $235.5 million of which was outstanding at December 31, 1998. The
interest rate payable on the facility at December 31, 1998 was 6.2%. The Company
has reached an agreement with the agent bank on a term sheet for a restated
facility which will reflect the following changes. The restated Revolving Credit
Facility is with a syndicate of banks and will provide for an aggregate
borrowing commitment of $300 million consisting of a $100 million 364-day
Revolving Credit Facility ("Tranche A") and a five year $200 million Revolving
Credit Facility ("Tranche B"). The Revolving Credit Facility will bear interest
at certain spreads over the Eurodollar rate, at the Federal Funds rate plus .50%
or at the agent bank's prime rate. The Company will have the option to determine
which rate will be used. The Company also will pay a facility fee on the
commitment. The interest rate spreads and facility fee will be adjusted based on
the Company's debt to capitalization ratio and will range from .75% to
2.00%. Pursuant to the Revolving Credit Facility, the Company will be required
to maintain a debt to capitalization ratio of not more than 60% through December
31, 2000 and of not more than 55% thereafter, and a senior debt to
capitalization ratio of not more than 40% beginning September 30,1999 through
December 31, 2001 and of not more than 35% thereafter. The agreement also
requires a ratio of EBITDA to interest and dividends on preferred stock as of
the end of any fiscal quarter of not less than 1.35 to 1.0 beginning June 30,
1999 increasing to 3.25 to 1.0 by December 31, 2002. Tranche A and Tranche B
will be reduced on a pro rata basis to a total of $250 million by September 30,
1999. The Revolving Credit Facility will be guaranteed and secured via a pledge
of the stock of the Company's significant subsidiaries. Documentation reflecting
this agreement is expected to be completed on or about the end of the first
quarter of 1999. The Company generally utilizes excess daily funds to reduce any
outstanding balances on the Revolving Credit Facility and associated interest
expense, and it intends to continue such practice.
21
Master Shelf Agreement. In December 1991, the Company entered into a
Master Shelf agreement (as amended and restated, the "Master Shelf") with The
Prudential Insurance Company of America ("Prudential"). Amounts outstanding
under the Master Shelf agreement at December 31, 1998 are as indicated in the
following table (000s):
Interest Final
Issue Date Amount Rate Maturity Principal Payments Due
- ------------------------------ -------- ----- ------------------ -----------------------------------------------
October 27, 1992 $ 16,667 7.51% October 27, 2000 $8,333 on each of October 27, 1999 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
--------
$191,667
========
The Company has reached an agreement on an amendment with Prudential which will
be effective as of January 1999 with the following provisions. The Company will
be 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 $300 million plus 50% of
consolidated net earnings earned from January 1, 1999 plus 75% of the net
proceeds of any equity offerings after January 1, 1999, and a debt to
capitalization ratio of not more than 60% through December 31, 2000 and of not
more than 55% thereafter. A senior debt to capitalization ratio will be
implemented, if and when, the Company issues subordinated debt. This amendment
also requires an EBITDA to interest ratio of not less than 1.75 to 1.0 beginning
March 31, 1999 increasing to a ratio of not less than 3.75 to 1.0 by March 31,
2002. Documentation reflecting this amendment is expected to be completed on or
about the end of the first quarter of 1999. In addition, under the existing
agreement, the Company is prohibited from declaring or paying dividends that in
the aggregate exceed the sum of $50 million plus 50% of consolidated net income
earned after June 30, 1995 (or minus 100% of a net loss), plus the aggregate net
cash proceeds received after June 30, 1995 from the sale of any stock. At
December 31, 1998, $51.5 million was available under this limitation. This
amount is expected to be reduced by approximately $14.9 million as a result of
the after-tax losses recognized on the sales of the Giddings and Katy
facilities. The Company presently intends to finance the $8.3 million payment
due on October 27, 1999 with amounts available under the Revolving Credit
Facility. The Master Shelf agreement is guaranteed and will be secured via a
pledge of the stock of the Company's significant subsidiaries.
1995 Senior Notes. In 1995, the Company sold $42 million of Senior Notes
(the "1995 Senior Notes") to a group of insurance companies with an interest
rate of 8.16% per annum. In February 1999, the Company offered to prepay the
1995 Senior Notes at par. Note holders representing $15 million of the principal
amount outstanding on the 1995 Senior Notes accepted the Company's offer and
were paid in full in March 1999. These payments were financed by the Bridge Loan
and by amounts available under the Revolving Credit Facility. The remaining
principal amount outstanding of $27 million is due in a single payment in
December 2005. The 1995 Senior Notes are guaranteed and will be secured via a
pledge of the stock of the Company's significant subsidiaries. The Company has
reached an agreement with the Note holders which provides for modification of
certain financial covenants on terms that will be no more restrictive than those
contained in the Master Shelf. Documentation reflecting this agreement is
expected to be completed on or about the end of the first quarter of 1999.
Effective January 1, 1999, the Company will pay an annual fee of no more than
.65% on the amounts outstanding on the Master Shelf and the 1995 Senior Notes.
This fee will continue until the Company has received an implied investment
grade rating on its senior secured debt.
1993 Senior Notes. In 1993, the Company sold $50 million of 7.65% Senior
Notes (the "1993 Senior Notes") to a group of insurance companies. Scheduled
annual principal payments of $7.1 million on the 1993 Senior Notes were made on
April 30 of 1997 and 1998. In February 1999, the Company offered to prepay the
1993 Senior Notes at par. Note holders representing approximately $33.5 million
of the total principal amount outstanding of $35.6 million accepted the
Company's offer and were paid in full in February 1999. These payments were
financed by a $37 million Bridge Loan. The Company intends to pay the remaining
outstanding principal of $2.1 million in the second quarter of 1999 with amounts
available under the Revolving Credit Facility.
Bridge Loan. In February 1999, in order to finance prepayments at par of
amounts outstanding on the 1993 and 1995 Senior Notes, the Company entered into
a Bridge Loan agreement in the amount of $37 million with its agent bank (the
"Bridge Loan"). The Bridge Loan bears interest at certain spreads over the
Eurodollar rate ranging from 1.75% at date of issuance to 2.75% at maturity. The
Bridge Loan may
22
be prepaid in whole or in part at any time and matures on October 31, 1999. The
Company presently intends to finance the payment of the Bridge Loan with amounts
available under the Revolving Credit Facility, proceeds from the sale of assets
or proceeds from the issuance of public debt.
Covenant Compliance. At December 31, 1998, the Company was in compliance
with all covenants in its loan agreements. Taking into account all the covenants
contained in these agreements, the Company had approximately $64.5 million of
available borrowing capacity at December 31, 1998. In March 1999, the Company
successfully completed negotiations with its lenders for amendments to its
various financing facilities providing for financial flexibility and covenant
modifications. These amendments were needed given the depressed commodity
pricing experienced in the industry in general and the disappointing results the
Company has experienced at its Bethel Treating Facility. There can be no
assurance that further amendments or waivers can be obtained in the future, if
necessary, or that the terms would be favorable to the Company. To strengthen
credit ratings and to reduce its overall debt outstanding, the Company will
continue to dispose of non-strategic assets (such as the Giddings and Katy
facilities) and investigate alternative financing sources (including the
issuance of public debt, project - financing, joint ventures and operating
leases).
Risk Management Activities
The Company's commodity price risk management program has two primary
objectives. The first goal is to preserve and enhance the value of the Company's
equity volumes of gas and NGLs with regard to the impact of commodity price
movements on cash flow, net income and earnings per share in relation to those
anticipated by the Company's operating budget. The second goal is to manage
price risk related to the Company's physical gas, crude oil and NGL marketing
activities to protect profit margins. This risk relates to hedging fixed price
purchase and sale commitments, preserving the value of storage inventories,
reducing exposure to physical market price volatility and providing risk
management services to a variety of customers.
The Company utilizes a combination of fixed price forward contracts, exchange-
traded futures and options, as well as fixed index swaps, basis swaps and
options traded in the over-the-counter ("OTC") market to accomplish these
objectives. These instruments allow the Company to preserve value and protect
margins because gains or losses in the physical market are offset by
corresponding losses or gains in the value of the financial instruments.
The Company uses futures, swaps and options to reduce price risk and basis risk.
Basis is the difference in price between the physical commodity being hedged and
the price of the futures contract used for hedging. Basis risk is the risk that
an adverse change in the futures market will not be completely offset by an
equal and opposite change in the cash price of the commodity being hedged.
Basis risk exists in natural gas primarily due to the geographic price
differentials between cash market locations and futures contract delivery
locations.
The Company enters into futures transactions on the New York Mercantile Exchange
("NYMEX") and the Kansas City Board of Trade and through OTC swaps and options
with various counterparties, consisting primarily of financial institutions and
other natural gas companies. The Company conducts its standard credit review of
OTC counterparties and has agreements with such parties that contain collateral
requirements. The Company generally uses standardized swap agreements that
allow for offset of positive and negative exposures. OTC exposure is marked to
market daily for the credit review process. The Company's OTC credit risk
exposure is partially limited by its ability to require a margin deposit from
its major counterparties based upon the mark-to-market value of their net
exposure. The Company is subject to margin deposit requirements under these
same agreements. In addition, the Company is subject to similar margin deposit
requirements for its NYMEX counterparties related to its net exposures.
The use of financial instruments may expose the Company to the risk of financial
loss in certain circumstances, including instances when (i) equity volumes are
less than expected, (ii) the Company's customers fail to purchase or deliver the
contracted quantities of natural gas or NGLs, or (iii) the Company's OTC
counterparties fail to perform. To the extent that the Company engages in
hedging activities, it may be prevented from realizing the benefits of favorable
price changes in the physical market. However, it is similarly insulated against
decreases in such prices.
The Company has hedged a portion of its equity volumes of gas and NGLs in 1999,
particularly in the first quarter, at pricing levels approximating its 1999
operating budget. The Company's equity hedging strategy establishes a minimum
and maximum price to the Company while allowing market participation between
these levels. As of February 19, 1999, the Company had hedged approximately 75%
of its anticipated equity gas for 1999 at a weighted average NYMEX-equivalent
minimum price of $2.00 per Mcf, including approximately 80% of first quarter
anticipated equity volumes at a weighted average NYMEX-equivalent minimum price
of $2.00 per Mcf. Additionally, the Company has hedged approximately 75% of its
anticipated equity NGLs for 1999 at a weighted average composite Mont Belvieu
and West Texas Intermediate Crude-equivalent minimum price of $.23 per gallon.
23
At December 31, 1998, the Company had $1.1 million of losses deferred in
inventory that will be recognized primarily during the first quarter of 1999 and
are expected to be offset by margins from the Company's related forward fixed
price hedges and physical sales. At December 31, 1998, the Company had
unrecognized net gains of $3.8 million related to financial instruments that are
expected to be offset by corresponding unrecognized net losses from the
Company's obligations to sell physical quantities of gas and NGLs.
The Company enters into speculative futures, swap and option trades on a very
limited basis for purposes that include testing of hedging techniques. The
Company's policies contain strict guidelines for such trading including
predetermined stop-loss requirements and net open positions limits. Speculative
futures, swap and option positions are marked to market at the end of each
accounting period and any gain or loss is recognized in income for that period.
Net gains or losses from such speculative activities for the years ended
December 31, 1998 and 1997 were not material.
Natural Gas Derivative Market Risk
As of December 31, 1998, the Company held a notional quantity of approximately
370 Bcf of natural gas futures, swaps and options extending from January 1999 to
December 2000 with a weighted average duration of approximately four months.
This was comprised of approximately 178 Bcf of long positions and 192 Bcf of
short positions in such instruments. As of December 31, 1997, the Company held a
notional quantity of approximately 480 Bcf of natural gas futures, swaps and
options extending from January 1998 to December 1999 with a weighted average
duration of approximately four months. This was comprised of approximately 230
Bcf of long positions and 250 Bcf of short positions in such instruments.
The Company uses a Value-at-Risk (VaR) model designed by J.P. Morgan as one
measure of market risk for the Company's natural gas portfolio. The VaR
calculated by this model represents the maximum change in market value over the
holding period at the specified statistical confidence interval. The VaR model
is generally based upon J.P. Morgan's RiskMetrics (TM) methodology using
historical price data to derive estimates of volatility and correlation for
estimating the contribution of tenor and location risk. The VaR model assumes a
one day holding period and uses a 95% confidence level.
As of December 31, 1998, the calculated VaR of the Company's entire natural gas
portfolio of futures, swaps and options was approximately $1.5 million. This
figure includes the risk related to the Company's entire portfolio of natural
gas financial instruments and does not include the related underlying hedged
physical transactions.
All financial instruments for which there are no offsetting physical
transactions are treated as either the hedge of an anticipated transaction or a
speculative trade. As of December 31, 1998, the VaR of these type of
transactions for natural gas was approximately $500,000.
Crude Oil and NGL Derivative Market Risk
As of December 31, 1998, the Company held a notional quantity of approximately
177,000 MGal of NGL futures, swaps and options extending from January 1999 to
December 1999 with a weighted average duration of approximately six months. This
was comprised of approximately 129,000 MGal of long positions and 48,000 MGal of
short positions in such instruments. As of December 31, 1997, the Company held a
notional quantity of approximately 148,000 MGal of NGL futures, swaps and
options extending from January 1998 to December 1998 with a weighted average
duration of approximately five months. This was comprised of approximately
93,000 MGal of long positions and 55,000 MGal of short positions in such
instruments.
As of December 31, 1998, the Company had sold 90,000 barrels per month of NYMEX
crude swaps for 1999 at an average price of $13.10 per barrel. In addition, the
Company had purchased 90,000 barrels per month of $15.00 per barrel NYMEX calls
for July 1999 through December 1999 settlement. The Company held no crude oil
futures, swaps or options for settlement beyond 1999.
As of December 31, 1998, the Company had purchased 200,000 barrels per month of
OPIS Mt. Belvieu monthly average settlement $0.210 per gallon puts to hedge a
portion of the Company's equity production of propane and butanes for 1999.
As of December 31, 1998, the Company had purchased 50,000 barrels per month of
OPIS Mt. Belvieu monthly average settlement $0.155 per gallon of purity ethane
puts to hedge a portion of the Company's equity production of ethane for 1999.
As of December 31, 1998, the Company held no NGL futures, swaps or options for
settlement beyond 1999.
24
As of December 31, 1998, the estimated fair value of the aforementioned crude
oil and NGL options held by the Company was approximately $315,000.
Foreign Currency Derivative Market Risk
The Company enters into physical gas transactions payable in Canadian dollars.
The Company enters into forward purchases and sales of Canadian dollars from
time to time to fix the cost of its future Canadian dollar denominated natural
gas purchase, sale, storage and transportation obligations. This is done to
protect marketing margins from adverse changes in the U.S. and Canadian dollar
exchange rate between the time the commitment for the payment obligation is made
and the actual payment date of such obligation. As of December 31, 1998, the
notional value of such contracts was approximately $11.0 million in Canadian
dollars. As of December 31, 1997, the notional value of such contracts was
approximately $5.5 million in Canadian dollars, which approximates its fair
market value.
Year 2000
The Company has made a comprehensive review of its computer systems to identify
the systems that could be affected by the "Year 2000" issue and is in the
process of identifying and making the appropriate modifications to these
computer systems. The Company has: (i) created a Year 2000 awareness program to
educate employees; (ii) compiled an inventory of all systems; (iii) developed
system test plans as appropriate; and (iv) began the testing and remediation as
required for both information and non-information technology systems.
Additionally, the Company has initiated a program under which it surveys its
business counterparties periodically regarding their Year 2000 conversion and
contingency plans. Currently, the Company anticipates spending approximately
$2.0 million, of which 30% is currently committed, for remediation purposes,
which is primarily for hardware and operating system upgrades. The Company also
expects to incur internal staff costs as well as some consulting and other
expenses which are expected to be immaterial. The Company anticipates its Year
2000 conversion project to be substantially completed by October 1999.
Currently, the Company believes its most significant risk for the Year 2000
issue is that the systems of other companies on which the Company relies will
not be Year 2000 compliant and that any such failure to convert by another
company would have an adverse effect on the Company. In order to mitigate this
risk, contingency plans are being developed and the Company is surveying its
vendors and customers to ascertain the status of their conversion and
contingency plans.
ENVIRONMENTAL
The construction and operation of the Company's gathering lines, plants and
other facilities used for the gathering, transporting, processing, treating or
storing of gas and NGLs are subject to federal, state and local environmental
laws and regulations, including those that can impose obligations to clean up
hazardous substances at the Company's facilities or at facilities to which the
Company sends wastes for disposal. In most instances, the applicable regulatory
requirements relate to water and air pollution control or waste management. The
Company employs six environmental engineers and seven regulatory compliance
specialists to monitor environmental and safety compliance 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 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 Texas Natural Resource Conservation Commission (the "TNRCC"), which has
authority to regulate, among other things, stationary air emissions sources,
created a committee to make recommendations to the TNRCC regarding a voluntary
emissions reduction plan for the permitting of existing "grandfathered" air
emissions sources within the State of Texas. A "grandfathered" air emissions
source is one that does not need a state operating permit because it was
constructed prior to 1971. The Company operates a number of such sources within
the State of Texas, including portions of its Midkiff plant and many of its
compressors. The recommendations proposed by the committee would create a
voluntary permitting program for grandfathered sources, including certain
incentives to participate, such as the ability to operate in such a source in a
flexible manner. It is not clear which of the committee's recommendations, if
any, that the TNRCC will implement and it is not possible to assess the
potential effect on the Company until final regulations are promulgated.
The Company anticipates that it is reasonably likely that the trend in
environmental legislation and regulation will continue to be towards stricter
standards. The Company is unaware of future environmental standards that are
reasonably likely to be adopted that will have a material effect on the
Company's financial position or results of operations, but it cannot rule out
that possibility.
25
The Company is in the process of voluntarily cleaning up substances at certain
facilities that it operates. The Company's expenditures for environmental
evaluation and remediation at existing facilities have not been significant in
relation to the results of operations of the Company and totaled approximately
$1.4 million for the year ended December 31, 1998 including approximately
$732,000 in air emissions fees to the states in which it operates ($132,000 of
which was attributable to the Edgewood facility which was sold in October 1998).
Although the Company anticipates that such environmental expenses per facility
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.
26
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements
Western Gas Resources, Inc.'s Consolidated Financial Statements as of December
31, 1998 and 1997 and for each of the three years in the period ended December
31, 1998:
Page
----
Report of Management....................................... 28
Report of Independent Accountants.......................... 29
Consolidated Balance Sheet................................. 30
Consolidated Statement of Cash Flows....................... 31
Consolidated Statement of Operations....................... 32
Consolidated Statement of Changes in Stockholders' Equity.. 33
Notes to Consolidated Financial Statements................. 34
27
REPORT OF MANAGEMENT
--------------------
The financial statements and other financial information included in this Annual
Report on Form 10-K are the responsibility of Management. The financial
statements have been prepared in conformity with generally accepted accounting
principles appropriate in the circumstances and include amounts that are based
on Management's informed judgments and estimates.
Management relies on the Company's system of internal accounting controls to
provide reasonable assurance that assets are safeguarded and that transactions
are properly recorded and executed in accordance with Management's
authorization. The concept of reasonable assurance is based on the recognition
that there are inherent limitations in all systems of internal accounting
control and that the cost of such systems should not exceed the benefits to be
derived. The internal accounting controls, including internal audit, in place
during the periods presented are considered adequate to provide such assurance.
The Company's financial statements are audited by PricewaterhouseCoopers LLP,
independent accountants. Their report states that they have conducted their
audit in accordance with generally accepted auditing standards. These standards
include an evaluation of the system of internal accounting controls for the
purpose of establishing the scope of audit testing necessary to allow them to
render an independent professional opinion on the fairness of the Company's
financial statements.
Oversight of Management's financial reporting and internal accounting control
responsibilities is exercised by the Board of Directors, through an Audit
Committee that consists solely of outside directors. The Audit Committee meets
periodically with financial management, internal auditors and the independent
accountants to review how each is carrying out its responsibilities and to
discuss matters concerning auditing, internal accounting control and financial
reporting. The independent accountants and the Company's internal audit
department have free access to meet with the Audit Committee without Management
present.
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)
28
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,
1998 and 1997, and the results of their cash flows and their operations for each
of the three years in the period ended December 31, 1998, 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.
PRICEWATERHOUSECOOPERS LLP
Denver, Colorado
March 22, 1999
29
WESTERN GAS RESOURCES, INC.
CONSOLIDATED BALANCE SHEET
(000s, except share data)
December 31
------------------------------------------
1998 1997
------------ ------------
ASSETS
------
Current assets:
Cash and cash equivalents.......................................... $ 4,400 $ 19,777
Trade accounts receivable, net..................................... 233,574 258,791
Product inventory.................................................. 46,207 17,261
Parts inventory.................................................... 10,153 9,405
Other.............................................................. 2,951 2,364
------------ ------------
Total current assets.......................................... 297,285 307,598
------------ ------------
Property and equipment:
Gas gathering, processing, storage and transmission................ 952,531 1,050,676
Oil and gas properties and equipment............................... 111,602 136,129
Construction in progress........................................... 87,943 64,268
------------ ------------
1,152,076 1,251,073
Less: Accumulated depreciation, depletion and amortization.............. (305,589) (294,350)
------------ ------------
Total property and equipment, net............................. 846,487 956,723
------------ ------------
Other assets:
Gas purchase contracts (net of accumulated amortization
of $29,978 and $27,554, respectively).............................. 41,263 43,687
Other.............................................................. 34,342 40,268
------------ ------------
Total other assets............................................ 75,605 83,955
------------ ------------
Total assets............................................................ $1,219,377 $1,348,276
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
-------------------------------------
Current liabilities:
Accounts payable................................................... 245,315 326,696
Accrued expenses................................................... 31,727 27,151
Dividends payable.................................................. 4,217 4,217
------------ ------------
Total current liabilities..................................... 281,259 358,064
Long-term debt.......................................................... 504,881 441,357
Deferred income taxes payable, net...................................... 48,021 80,743
------------ ------------
Total liabilities............................................. 834,161 880,164
------------ ------------
Commitments and contingent liabilities.................................. - -
Stockholders' equity:
Preferred Stock; 10,000,000 shares authorized:
$2.28 cumulative preferred stock, par value $.10;
1,400,000 shares issued ($35,000,000 aggregate
liquidation preference)....................................... 140 140
$2.625 cumulative convertible preferred stock, par value $.10;
2,760,000 shares issued (138,000,000 aggregate liquidation
preference)................................................... 276 276
Common stock, par value $.10; 100,000,000 shares authorized;
32,173,009 and 32,171,453 shares issued, respectively......... 3,217 3,217
Treasury stock, at cost; 25,016 shares in treasury................. (788) (788)
Additional paid-in capital......................................... 397,344 397,321
Retained (deficit) earnings........................................ (17,075) 66,999
Accumulated other comprehensive income............................. 3,053 2,233
Notes receivable from key employees secured by common stock........ (951) (1,286)
------------ ------------
Total stockholders' equity.................................... 385,216 468,112
------------ ------------
Total liabilities and stockholders' equity.............................. $1,219,377 $1,348,276
============ ============
The accompanying notes are an integral part of the consolidated financial
statements.
30
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(000s)
Year Ended December 31,
--------------------------------------
1998 1997 1996
----------- ----------- -----------
Reconciliation of net income (loss) to net cash provided by (used in) operating activities:
Net income (loss).......................................................................... $ (67,205) $ 1,487 $ 27,941
Add income items that do not affect cash:
Depreciation, depletion and amortization.................................................. 59,346 59,248 63,207
Deferred income taxes.................................................................... (32,722) 465 12,538
Distributions in excess of equity income, net............................................ 963 1,764 4,339
Gain on the sale of property and equipment............................................... (16,478) (4,681) (2,747)
Loss on the impairment of property and equipment......................................... 108,447 34,615 -
Other non-cash items, net................................................................ 2,595 3,250 336
---------- ---------- ----------
54,946 96,148 105,614
---------- ---------- ----------
Adjustments to working capital to arrive at net cash provided by (used in)
operating activities:
Decrease (increase) in trade accounts receivable......................................... 25,317 79,963 (134,538)
Decrease (increase) in product inventory................................................. (29,810) 7,480 2,115
Increase in parts inventory.............................................................. (748) (6,806) (172)
Increase in other current assets......................................................... (587) (1,027) (42)
Decrease (increase) in other assets and liabilities, net................................. 257 257 (733)
(Decrease) increase in accounts payable.................................................. (81,381) (59,572) 186,758
(Decrease) increase in accrued expenses.................................................. (3,564) (1,688) 9,264
---------- ---------- ----------
Total adjustments...................................................................... (90,516) 18,607 62,652
---------- ---------- ----------
Net cash provided by (used in) operating activities....................................... (35,570) 114,755 168,266
---------- ---------- ----------
Cash flows from investing activities:
Purchases of property and equipment, including acquisitions.............................. (104,171) (196,293) (74,203)
Proceeds from the disposition of property and equipment.................................. 75,286 20,034 7,656
Contributions to unconsolidated affiliates............................................... (1,045) (2,608) (352)
Distribution from unconsolidated affiliates.............................................. 3,489 - 1,500
---------- ---------- ----------
Net cash used in investing activities..................................................... (26,441) (178,867) (65,399)
---------- ---------- ----------
Cash flows from financing activities:
Net proceeds from issuance of common stock............................................... - - 96,376
Net proceeds from exercise of common stock options....................................... 23 239 62
Payments on long-term debt............................................................... (15,476) (94,643) (12,500)
Borrowings under revolving credit facility............................................... 3,230,400 1,894,950 1,035,377
Payments on revolving credit facility.................................................... (3,151,400) (1,738,450) (1,172,877)
Debt issue costs paid.................................................................... (44) (847) -
Dividends paid........................................................................... (16,869) (16,864) (15,596)
---------- ---------- ----------
Net cash provided by (used in) financing activities....................................... 46,634 44,385 (69,158)
---------- ---------- ----------
Net (decrease) increase in cash........................................................... (15,377) (19,727) 33,709
Cash and cash equivalents at beginning of year............................................ 19,777 39,504 5,795
---------- ---------- ----------
Cash and cash equivalents at end of year.................................................. $ 4,400 $ 19,777 $ 39,504
========== ========== ==========
The accompanying notes are an integral part of the consolidated financial
statements.
31
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
(000s, except share and per share amounts)
Year Ended December 31,
----------------------------------------
1998 1997 1996
------------ ------------ ------------
Revenues:
Sale of gas............................................................. $ 1,611,521 $ 1,657,479 $ 1,440,882
Sale of natural gas liquids............................................. 449,696 611,969 561,581
Processing, transportation and storage revenue.......................... 44,743 40,906 44,943
Sale of electric power.................................................. 20 59,477 30,667
Other, net.............................................................. 27,586 15,429 12,936
----------- ----------- -----------
Total revenues........................................................ 2,133,566 2,385,260 2,091,009
----------- ----------- -----------
Costs and expenses:
Product purchases....................................................... 1,914,303 2,146,430 1,844,151
Plant operating expense................................................. 85,353 78,113 73,116
Oil and gas exploration and production costs............................ 7,996 7,714 5,056
Depreciation, depletion and amortization................................ 59,346 59,248 63,207
Selling and administrative expense...................................... 30,128 29,446 29,411
Interest expense........................................................ 33,616 27,474 34,437
Loss on the impairment of property and equipment........................ 108,447 34,615 -
----------- ----------- -----------
Total costs and expenses.............................................. 2,239,189 2,383,040 2,049,378
----------- ----------- -----------
Income (loss) before income taxes........................................ (105,623) 2,220 41,631
Provision (benefit) for income taxes:
Current................................................................. (5,696) 268 1,152
Deferred................................................................ (32,722) 465 12,538
----------- ----------- -----------
Total provision (benefit) for income taxes............................. (38,418) 733 13,690
----------- ----------- -----------
Net income (loss)........................................................ (67,205) 1,487 27,941
Preferred stock requirements............................................. (10,439) (10,439) (10,439)
----------- ----------- -----------
Income (loss) attributable to common stock............................... $ (77,644) $ (8,952) $ 17,502
=========== =========== ===========
Earnings (loss) per share of common stock................................ $ (2.42) $ (.28) $ .66
=========== =========== ===========
Weighted average shares of common stock outstanding...................... 32,147,354 32,134,011 26,519,635
=========== =========== ===========
Earnings (loss) per share of common stock - assuming dilution............ $ (2.42) $ (.28) $ .66
=========== =========== ===========
Weighted average shares of common stock outstanding - assuming dilution.. 32,147,354 32,137,803 26,541,565
=========== =========== ===========
The accompanying notes are an integral part of the consolidated financial
statements.
32
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
(000s, except share amounts)
Shares of
Shares of $2.625
$ 2.28 Cumulative Shares
Cumulative Convertible Shares of Common
Preferred Preferred of Common Stock
Stock Stock Stock in Treasury
----------- ------------- ----------- -------------
Balance at December 31, 1995............... 1,400,000 2 ,760,000 25,769,712 25,016
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
Net income, 1997........................... - - - -
Stock options exercised.................... - - 37,302 -
Tax benefit related to stock options....... - - - -
Loans forgiven............................. - - - -
Dividends declared on common stock......... - - - -
Dividends declared on $2.28 cumulative
preferred stock........................... - - - -
Dividends declared on $2.625 cumulative
convertible preferred stock............... - - - -
----------- ------------- ----------- -------------
Balance at December 31, 1997............... 1,400,000 2,760,000 32,146,437 25,016
Net income 1998............................ - - - -
Stock options exercised.................... - - 1,556 -
Loans forgiven............................. - - - -
Dividends declared on common stock......... - - - -
Dividends declared on $2.28 cumulative
preferred stock......................... - - - -
Dividends declared on $2.625 cumulative
convertible preferred stock.............. - - - -
Translation adjustments.................... - - - -
----------- ------------- ----------- -------------
Balance at December 31, 1998.............. 1,400,000 2,760,000 32,147,993 25,016
=========== ============= =========== =============
$2.625
$2.28 Cumulative
Cumulative Convertible
Preferred Preferred Common Treasury
Stock Stock Stock Stock
----------- ------------- ----------- -------------
Balance at December 31, 1995............... $ 140 $ 276 $2,580 $(788)
Net income, 1996........................... - - - -
Stock options exercised.................... - - 1 -
Loans forgiven............................. - - - -
Common stock offering...................... - - 632 -
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............... 140 276 3,213 (788)
Net income, 1997........................... - - - -
Stock options exercised.................... - - 4 -
Tax benefit related to stock options....... - - - -
Loans forgiven............................. - - - -
Dividends declared on common stock......... - - - -
Dividends declared on $2.28 cumulative
preferred stock........................... - - - -
Dividends declared on $2.625 cumulative
convertible preferred stock............... - - - -
----------- ------------- ----------- -------------
Balance at December 31, 1997............... 140 276 3,217 (788)
Net income 1998............................ - - - -
Stock options exercised.................... - - - -
Loans forgiven............................. - - - -
Dividends declared on common stock......... - - - -
Dividends declared on $2.28 cumulative
preferred stock......................... - - - -
Dividends declared on $2.625 cumulative
convertible preferred stock............. - - - -
Translation adjustments.................... - - - -
----------- ------------- ----------- -------------
Balance at December 31, 1998.............. $ 140 $ 276 $3,217 $(788)
=========== ============= =========== =============
Accumulated Notes Total
Additional Retained Other Receivable Stock-
Paid-In (Deficit) Comprehensive from Key holders'
Capital Earnings Income Employees Equity
----------- ------------- ----------- ------------- -------------
Balance at December 31, 1995............... $301,234 $ 70,348 $ - $(1,881) $371,909
Net income, 1996........................... - 27,941 - - 27,941
Stock options exercised.................... 83 - - (24) 60
Loans forgiven............................. - - - 92 92
Common stock offering...................... 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............... 397,061 82,378 - (1,813) 480,467
Net income, 1997........................... - 1,487 - - 1,487
Stock options exercised.................... 260 - - (25) 239
Tax benefit related to stock options....... - - 2,233 - 2,233
Loans forgiven............................. - - - 552 552
Dividends declared on common stock......... - (6,427) - - (6,427)
Dividends declared on $2.28 cumulative
preferred stock........................... - (3,194) - - (3,194)
Dividends declared on $2.625 cumulative
convertible preferred stock............... - (7,245) - - (7,245)
----------- ------------- ----------- ------------- -------------
Balance at December 31, 1997............... 397,321 66,999 2,233 (1,286) 468,112
Net income 1998............................ - (67,205) - - (67,205)
Stock options exercised.................... 23 - - - 23
Loans forgiven............................. - - - 335 335
Dividends declared on common stock......... - (6,430) - - (6,430)
Dividends declared on $2.28 cumulative
preferred stock......................... - (3,194) - - (3,194)
Dividends declared on $2.625 cumulative
convertible preferred stock.............. - (7,245) - - (7,245)
Translation adjustments.................... - - 820 - 820
----------- ------------- ----------- ------------- -------------
Balance at December 31, 1998.............. $397,344 $(17,075) $3,053 $ (951) $385,216
============ ============= ============ ============= =============
The accompanying notes are an integral part of the consolidated financial
statements.
33
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - NATURE OF ORGANIZATION
- -------------------------------
Western Gas Resources, Inc. (the "Company") is an independent gas gatherer and
processor and energy marketer providing a full range of services to its
customers from the wellhead to the delivery point. The Company designs,
constructs, owns and operates natural gas gathering, processing, treating and
storage facilities in major gas-producing basins in the Rocky Mountain, Mid-
Continent, Gulf Coast and Southwestern regions of the United States. The Company
connects producers' wells to its gathering systems for delivery to its
processing or treating plants, processes the natural gas to extract natural gas
liquids ("NGLs") and treats the natural gas in order to meet pipeline
specifications. The Company markets gas and NGLs nationwide and in Canada,
providing risk management, storage, transportation, scheduling, peaking and
other services to a variety of customers. The Company owns and operates certain
producing properties, primarily in Wyoming and Louisiana. The Company also
explores and develops gas reserves, primarily in Wyoming, in support of its
existing facilities.
Western Gas Resources, Inc. was formed in October 1989 to acquire a majority
interest in Western Gas Processors, Ltd. (the "Partnership") and to assume the
duties of WGP Company, the general partner of the Partnership. The Partnership
was a Colorado limited partnership formed in 1977 to engage in the gathering and
processing of natural gas. The reorganization was accomplished in December 1989
through an exchange for common stock of partnership units held by the former
general partners of WGP Company and an initial public offering of Western Gas
Resources, Inc. Common Stock. On May 1, 1991, a further restructuring
("Restructuring") of the Partnership and Western Gas Resources, Inc. (together
with its predecessor, WGP Company, collectively, the "Company") was approved by
a vote of the security holders. The combinations were reorganizations of
entities under common control and were accounted for at historical cost in a
manner similar to poolings of interests.
The Company has completed three public offerings of Common Stock. In December
1989, the Company issued 3,527,500 shares of Common Stock at a public offering
price of $11.50. In November 1991, the Company issued 4,115,000 shares of
Common Stock at a public offering price of $18.375 per share. In November 1996,
the Company issued 6,325,000 shares of Common Stock at a public offering price
of $16.25 per share. The net proceeds to the Company from the November 1996
public offering of Common Stock of $96.4 million were primarily used to reduce
indebtedness under the Revolving Credit Facility.
The Company has also issued preferred stock in a private transaction and has
completed two public offerings of preferred stock. In October 1991, the Company
issued 400,000 shares of 7.25% Cumulative Senior Perpetual Convertible Preferred
Stock ("7.25% Preferred Stock") with a liquidation preference of $100 per share
to an institutional investor. In May 1995, the Company redeemed all of the
issued and outstanding shares of its 7.25% Preferred Stock pursuant to the
provisions of its Certificate of Designation relating to such preferred stock,
at an aggregate redemption price of approximately $42.0 million, including a
redemption premium of $2.0 million. In November 1992, the Company issued
1,400,000 shares of $2.28 Cumulative Preferred Stock with a liquidation
preference of $25 per share, at a public offering price of $25 per share,
redeemable at the Company's option on or after November 15, 1997. In February
1994, the Company issued 2,760,000 shares of $2.625 Cumulative Convertible
Preferred Stock with a liquidation preference of $50 per share, at a public
offering price of $50 per share, redeemable at the Company's option on or after
February 16, 1997 and convertible at the option of the holder into Common Stock
at a conversion price of $39.75.
SIGNIFICANT BUSINESS ACQUISITIONS, DISPOSITIONS AND PROJECTS
Coal Bed Methane
The Company is expanding its Powder River Basin coal bed methane natural gas
gathering system and developing its own coal seam gas reserves in Wyoming. The
Company has acquired drilling rights in the vicinity of known coal bed methane
production. During the years ended December 31, 1998, 1997 and 1996, the
Company has expended approximately $46.7 million, $32.2 million and $6.9
million, respectively, on this project. On October 30, 1997, the Company sold a
50% undivided interest in its Powder River Basin coal bed methane gas
operations. The final adjusted purchase price was $17.9 million, resulting in a
pre-tax gain of $4.7 million, which was recognized in the fourth quarter of
1997.
In December 1998, the Company joined with other industry participants to form
the Fort Union Gas Gathering, L.L.C., which plans to build a 106-mile, 24-inch
gathering header to gather coal bed methane in the Powder River Basin in
northeast Wyoming. The Company will have an approximate 13% interest and be the
construction contractor and field operator of the header and a related gas
treating facility. Construction is scheduled to begin in April 1999 with
operations to commence on or about the end of the third quarter
34
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
of 1999. It is anticipated that the new gathering header and treating system
will be project-financed, requiring a cash investment by the Company of
approximately $2 million.
Southwest Wyoming
The Company's facilities in Southwest Wyoming are comprised of the Granger
facility and a 72% ownership interest in the Lincoln Road facility (collectively
the "Granger Complex"). The Company began to expand its gas gathering and
exploration and production activities in Southwest Wyoming during 1997. The
expansion in this area is primarily intended to develop acreage to replace
declines in reserves and generate additional volumes for gathering and
processing at its facilities. During the years ended December 31, 1998 and
1997, the Company has expended approximately $16.0 million and $6.2 million,
respectively, on this project. In February 1998, the Company sold a 50%
undivided interest in a small portion of the Granger gathering system for
approximately $4.0 million. This amount approximated the Company's cost in such
facilities.
In 1997, the Company granted an option to an affiliate of a producer behind the
Granger Complex to purchase up to 50% of the Granger Complex. In conjunction
with this agreement, in February 1998, the Company received a $1 million non-
refundable option payment. The option to acquire an interest in these
facilities expired in the fourth quarter of 1998.
Bethel Treating Facility
In 1996 and 1997 the Pinnacle Reef trend was rapidly developing into a very
active lease acquisition and exploratory play using 3-D seismic technology. The
initial discoveries in the play indicated a very large potential gas
development. Based on the Company's receipt of large acreage dedications in this
area, the Company constructed the Bethel Treating facility for a total cost of
approximately $102.8 million with a throughput capacity of 350 MMcf per day.
In 1998, the production rates from the wells drilled in this field and the
recoverable reserves from these properties, were far less than originally
expected by the producers. As a result, in 1998, the Bethel Treating facility
averaged gas throughput of approximately 61 Mmcf per day. Due to the unexpected
poor drilling results and reductions in the producers' drilling budgets, the
number of rigs active in this area has decreased from 18 in July 1998 to one
active rig in March 1999.
In 1998, the Company completed the construction of the Bethel Treating facility
in East Texas that gathers gas from the Cotton Valley Pinnacle Reef trend, for
a total cost of approximately $102.8 million. Because of uncertainties related
to the pace and success of third-party drilling programs, declines in volumes
produced at certain wells and other conditions outside of the Company's control,
the Company determined that a pre-tax, non-cash impairment charge of $77.8
million in the fourth quarter of 1998 was required.
Edgewood
In two transactions which closed in October 1998 the Company sold its Edgewood
gathering system, including its undivided interest in the producing properties
associated with this facility, and its 50% interest in the Redman Smackover
Joint Venture ("Redman Smackover"). The combined sales price was $55.8 million.
The proceeds from these sales were used to repay a portion of the balances
outstanding under the Revolving Credit Facility. After the accrual of certain
related expenses, the Company recognized a pre-tax gain of approximately $1.6
million, during the fourth quarter of 1998.
Perkins
In November 1997, the Company entered into an agreement to sell its Perkins
facility. In March 1998, the Company completed the sale of this facility with
an effective date of January 1, 1998. The sales price was $22.0 million and
resulted in a pre-tax gain of approximately $14.9 million. The proceeds from
this sale were used to repay a portion of the balances outstanding under the
Revolving Credit Facility.
35
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
SUBSEQUENT EVENTS
Giddings
In March 1999, the Company entered into an agreement to sell its Giddings
Facility for $36.0 million, which will result in an approximate pre-tax loss
of $4.8 million. This agreement is subject to various approvals and is
anticipated to close in the second quarter of 1999.
Katy
In March 1999, the Company entered into an agreement to sell all of the
outstanding common stock of its wholly-owned subsidiary, Western Gas Resources
Storage, Inc., for $100.0 million, which will result in an approximate pre-tax
loss of $18.5 million. The only asset of this subsidiary is the Katy Facility.
This agreement is subject to various regulatory approvals and the satisfaction
of certain contractual conditions and is anticipated to close in the second
quarter of 1999. The Company has the option to sell approximately 5.4 Bcf of
stored gas in the Katy Facility to the same purchaser for total sales proceeds
of approximately $10.0 million (which would approximate its cost of the
inventory). To meet the needs of its marketing operations, the Company will
continue to contract for storage capacity. Accordingly, the Company will enter
into a long-term agreement with the purchaser for 3 Bcf of storage capacity at
market rates.
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.
Inventories
For the years ended December 31, 1998 and 1997, the cost of gas and NGL
inventories is determined by the weighted average cost on a location-by-location
basis. Prior to 1997, the cost of NGL inventories was determined by the last-
in, first-out (LIFO) method, on a location-by-location basis. The change in
accounting method from LIFO to weighted average cost was not material. As a
result, prior year financial statements were not restated. Residue and NGL
inventory covered by hedging contracts is accounted for on a specific
identification basis. Product inventory includes $42.8 million and $11.9
million of gas and $3.4 million and $5.4 million of NGLs at December 31, 1998
and 1997, respectively. During the years ended December 31, 1998 and 1997, the
Company recorded lower of cost or market write-downs of NGL inventories of
$826,000 and $1.1 million, respectively.
Property and Equipment
Property and equipment is recorded at the lower of cost, including interest on
funds borrowed to finance the construction of new projects, or estimated
realizable value. Interest incurred during the construction period of new
projects is capitalized and amortized over the life of the associated assets.
Depreciation is provided using the straight-line method based on the estimated
useful life of each facility which ranges from three to 35 years. Useful lives
are determined based on the shorter of the life of the equipment or the reserves
serviced by the equipment. The cost of acquired gas purchase contracts is
amortized using the straight-line method.
36
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Oil and Gas Properties and Equipment
The Company follows the successful efforts method of accounting for oil and gas
exploration and production activities. Acquisition costs, development costs and
successful exploration costs are capitalized. Exploratory dry hole costs, lease
rentals and geological and geophysical costs are charged to expense as incurred.
Upon surrender of undeveloped properties, the original cost is charged against
income. Producing properties and related equipment are depleted and depreciated
by the units-of-production method based on estimated proved reserves for
producing properties and proved developed reserves for lease and well equipment.
Income Taxes
Deferred income taxes reflect the impact of temporary differences between
amounts of assets and liabilities for financial reporting purposes and such
amounts as measured by tax laws. These temporary differences are determined and
accounted for in accordance with SFAS No. 109, "Accounting for Income Taxes."
Foreign Currency Adjustments
During the second quarter of 1997, the Company began operating a subsidiary in
Canada. The assets and liabilities associated with this subsidiary are
translated into U.S. dollars at the exchange rate as of the balance sheet date
and revenues and expenses at the weighted-average of exchange rates in effect
during each reporting period. SFAS No. 52, "Foreign Currency Translation,"
requires that cumulative translation adjustments be reported as a separate
component of stockholders' equity. The translation adjustment for the year
ended December 31, 1998 was $820,000. The adjustment for the year ended
December 31, 1997 was not material.
Revenue Recognition
Revenue for sales or services is recognized at the time the gas, NGLs or
electric power is delivered or at the time the service is performed.
Comprehensive Income
In June 1997, the Financial Accounting Standards Board issued SFAS No. 130,
"Reporting Comprehensive Income," ("SFAS No. 130") effective for fiscal years
beginning after December 15, 1997. SFAS No. 130 requires that changes in items
of comprehensive income be reported as a separate component of stockholders'
equity. The Company's cumulative translation adjustments of $820,000 for the
year ended December 31, 1998 and tax benefits related to stock options of $2.2
million for the year ended December 31, 1997 are separately reported on the
Consolidated Statement of Changes in Stockholders' Equity.
Gas and NGL Hedges
Gains and losses on hedges of product inventory are included in the carrying
amount of the inventory and are ultimately recognized in gas and NGL sales when
the related inventory is sold. Gains and losses related to qualifying hedges,
as defined by SFAS No. 80, "Accounting for Futures Contracts," of firm
commitments or anticipated transactions (including hedges of equity production)
are recognized in gas and NGL sales, as reported on the Consolidated Statement
of Operations, when the hedged physical transaction occurs. For purposes of
the Consolidated Statement of Cash Flows, all hedging gains and losses are
classified in net cash provided by operating activities. To the extent the
Company engages in speculative transactions, they are marked to market at the
end of each accounting period and any gain or loss is recognized in income for
that period.
Impairment of Long-Lived Assets
The Company complies with SFAS No. 121, "Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to be Disposed of" ("SFAS No. 121"). The
Company reviews its assets at the plant facility and oil and gas producing
property levels. SFAS No. 121 also requires long-lived assets be reviewed
whenever events or changes in circumstances indicate that the carrying value of
such assets may not be recoverable. In order to determine whether an impairment
exists, the Company
37
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
compares its net book value of the asset to the estimated fair market value or
the undiscounted expected future cash flows, determined by applying future
prices estimated by management over the shorter of the lives of the facilities
or the reserves supporting the facilities. If an impairment exists, write-downs
of assets are based upon expected cash flows discounted using an interest rate
commensurate with the risk associated with the underlying asset. The Company has
written-down property and equipment of $108.5 million and $34.6 million in
accordance with SFAS No. 121 during the years ended December 31, 1998 and 1997,
respectively.
Earnings (Loss) Per Share of Common Stock
The Company follows SFAS No. 128, "Earnings per Share" ("SFAS No. 128") which
requires that earnings per share and earnings per share - assuming dilution be
calculated and presented on the face of the statement of operations. In
accordance with SFAS No. 128, earnings (loss) per share of common stock is
computed by dividing income (loss) attributable to common stock by the weighted
average shares of common stock outstanding. In addition, earnings (loss) per
share of common stock -assuming dilution is computed by dividing income (loss)
attributable to common stock by the weighted average shares of common stock
outstanding as adjusted for potential common shares. Income (loss) attributable
to common stock is income (loss) less preferred stock dividends. The Company
declared preferred stock dividends of $10.4 million for each of the years ended
December 31, 1998, 1997 and 1996, respectively. Common stock options, which
are potential common shares, had a dilutive effect on earnings per share and
increased the weighted average shares of common stock outstanding by 3,792 and
21,930 shares for the years ended December 31, 1997 and 1996, respectively.
The Common Stock options were anti-dilutive in 1998, therefore the numerator and
denominator for the year ended December 31, 1998 were not adjusted. SFAS No.
128 dictates that the computation of earnings per share shall not assume
conversion, exercise or contingent issuance of securities that would have an
antidilutive effect on earnings (loss) per share. As a result, the numerators
and the denominators for each of the three years ended December 31, 1998 are not
adjusted to reflect the Company's $2.625 Cumulative Convertible Preferred Stock
outstanding. The shares are antidilutive as the incremental shares result in an
increase in earnings per share, or a reduction of loss per share, after giving
affect to the dividend requirements.
Concentration of Credit Risk
Financial instruments which potentially subject the Company to concentrations of
credit risk consist principally of trade accounts receivable and over-the-
counter ("OTC") swaps and options. The risk is limited due to the large number
of entities comprising the Company's customer base and their dispersion across
industries and geographic locations. At December 31, 1998, 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 $36.1 million, $33.1 million and $36.7 million, respectively,
for the years ended December 31, 1998, 1997 and 1996. Capitalized interest
associated with construction of new projects was $2.5 million, $5.1 million and
$1.7 million, respectively, for the years ended December 31, 1998, 1997 and
1996.
Income taxes paid were $0, $2.6 million and $4.2 million, respectively, for the
years ended December 31, 1998, 1997 and 1996.
Stock Compensation
As permitted under SFAS No. 123, "Accounting for Stock-Based Compensation"
("SFAS No. 123"), the Company has elected to continue to measure compensation
costs for stock-based employee compensation plans as prescribed by Accounting
Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees"
("APB No. 25"). The Company has complied with the pro forma disclosure
requirements of SFAS No. 123 as required under the pronouncement.
38
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The Company realizes an income tax benefit from the exercise of non-qualified
stock options related to the difference between the market price at the date of
exercise and the option price. APB No. 25 requires that this difference be
credited to additional paid-in capital. In September 1997, the Company recorded
a credit of $2.2 million to Additional Paid-In Capital to reflect such
difference associated with the Company's $5.40 Stock Option Plan.
Use of Estimates and Significant Risks
The preparation of consolidated financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the amounts reported in these financial statements
and accompanying notes. The more significant areas requiring the use of
estimates relate to oil and gas reserves, fair value of financial instruments,
future cash flows associated with assets and useful lives for depreciation,
depletion and amortization. Actual results could differ from those estimates.
The Company is subject to a number of risks inherent in the industry in which it
operates, primarily fluctuating prices and gas supply. The Company's financial
condition and results of operations will depend significantly upon the prices
received for gas and NGLs. These prices are subject to fluctuations in response
to changes in supply, market uncertainty and a variety of additional factors
that are beyond the control of the Company. In addition, the Company must
continually connect new wells to its gathering systems in order to maintain or
increase throughput levels to offset natural declines in dedicated volumes. The
number of new wells drilled will depend upon, among other factors, prices for
gas and oil, the drilling budgets of third-party producers, the energy policy of
the federal government and the availability of foreign oil and gas, none of
which are within the Company's control.
Accounting for Derivative Instruments and Hedging Activities
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS No. 133"),
effective for fiscal years beginning after June 15, 1999. Under SFAS No. 133,
the Company will be required to recognize all derivatives as either assets or
liabilities in the statement of financial position and measure those instruments
at fair value. Changes in the fair value of derivatives are recorded each period
in current earnings or other comprehensive income depending upon the nature of
the underlying transaction. The Company has not yet determined the impact that
the adoption of SFAS No. 133 will have on its earnings or financial position.
Reclassifications
Certain prior years' amounts in the consolidated financial statements and
related notes have been reclassified to conform to the presentation used in
1998.
NOTE 3 - RELATED PARTIES
- ------------------------
The Company enters into joint ventures and partnerships in order to reduce risk,
create strategic alliances and to establish itself in oil and gas producing
basins in the United States. For the years ended December 31, 1998, 1997 and
1996, the Company had a 50% ownership interest in Williston Gas Company
("Williston") and Westana Gathering Company ("Westana"). In addition, for the
years ended December 31, 1997 and 1996 the Company also had a 50% ownership
interest in Redman Smackover. This interest was sold effective July 1, 1998.
The Company acts as operator for Williston and Westana. The Company also has a
49% interest in the Sandia Energy Resources Joint Venture ("Sandia"), which was
formed in March 1996. The Company's share of equity income or loss in these
ventures is reflected in Other net revenue. All transactions entered into by
the Company with its related parties are consummated in the ordinary course of
business.
Historically, the Company had purchased a significant portion of the production
of Williston. The Company also performed various operational and administrative
functions for Williston and charged a monthly overhead fee to cover such
services. In August 1996, substantially all of the assets associated with
Williston were sold to a third party. The Company expects that Williston will
be dissolved during 1999. At December 31, 1998, the Company's investment in
Williston was immaterial.
39
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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. At December 31, 1998, the Company's
investment in Westana was $26.9 million.
The Company provides substantially all of the natural gas that Sandia markets
and also provides various administrative services to Sandia. In addition, the
Company purchases gas from Sandia. The Company records receivable and payable
balances at the end of each accounting period related to the above referenced
transactions. At December 31, 1998, the Company's investment in Sandia was
$546,000. Sandia will be dissolved in the first quarter of 1999.
The following table summarizes account balances reflected in the financial
statements (000s):
As of or for the Year Ended December 31,
----------------------------------------
1998 1997 1996
------------ ------------ ------------
Trade accounts receivable.. $ 3,794 $ 4,295 $ 5,552
======= ======= =======
Accounts payable........... 9,474 7,246 11,041
======= ======= =======
Sales of gas and NGLs...... 31,319 19,504 10,592
======= ======= =======
Processing revenue......... 192 336 256
======= ======= =======
Product purchases.......... 58,899 59,082 57,675
======= ======= =======
Administrative expense..... $ 483 $ 421 $ 419
======= ======= =======
The Company has entered into agreements committing the Company to loan to
certain key employees an amount sufficient to exercise their options as each
portion of their options vests under the Key Employees' Incentive Stock Option
Plan and the $5.40 Stock Option Plan (see Note 10). The Company will forgive
the loan and accrued interest if the employee has been continuously employed by
the Company for periods specified under the agreements and Board of Directors'
resolutions. As of December 31, 1998 and 1997, loans totaling $951,000 and $1.3
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 1998 and 1997, the Board of Directors approved the forgiveness
of loans to certain employees totaling approximately $335,000 and $552,000,
respectively, in connection with these plans.
NOTE 4 - COMMODITY RISK MANAGEMENT
- ----------------------------------
Gas and NGL Hedges
The Company's commodity price risk management program has two primary
objectives. The first goal is to preserve and enhance the value of the
Company's equity volumes of gas and NGLs with regard to the impact of commodity
price movements on cash flow, net income and earnings per share in relation to
those anticipated by the Company's operating budget. The second goal is to
manage price risk related to the Company's physical gas, crude oil and NGL
marketing activities to protect profit margins. This risk relates to hedging
fixed price purchase and sale commitments, preserving the value of storage
inventories, reducing exposure to physical market price volatility and providing
risk management services to a variety of customers.
The Company utilizes a combination of fixed price forward contracts, exchange-
traded futures and options, as well as fixed index swaps, basis swaps and
options traded in the over-the-counter ("OTC") market to accomplish these
objectives. These instruments allow the Company to preserve value and protect
margins because gains or losses in the physical market are offset by
corresponding losses or gains in the value of the financial instruments.
The Company uses futures, swaps and options to reduce price risk and basis risk.
Basis is the difference in price between the physical commodity being hedged and
the price of the futures contract used for hedging. Basis risk is the risk that
an adverse change in the futures market will not be completely offset by an
equal and opposite change in the cash price of the commodity being hedged.
Basis
40
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
risk exists in natural gas primarily due to the geographic price differentials
between cash market locations and futures contract delivery locations.
The Company enters into futures transactions on the New York Mercantile Exchange
("NYMEX") and the Kansas City Board of Trade and through OTC swaps and options
with various counterparties, consisting primarily of financial institutions and
other natural gas companies. The Company conducts its standard credit review of
OTC counterparties and has agreements with such parties that contain collateral
requirements. The Company generally uses standardized swap agreements that
allow for offset of positive and negative exposures. OTC exposure is marked to
market daily for the credit review process. The Company's OTC credit risk
exposure is partially limited by its ability to require a margin deposit from
its major counterparties based upon the mark-to-market value of their net
exposure. The Company is subject to margin deposit requirements under these
same agreements. In addition, the Company is subject to similar margin deposit
requirements for its NYMEX counterparties related to its net exposures.
The use of financial instruments may expose the Company to the risk of financial
loss in certain circumstances, including instances when (i) equity volumes are
less than expected, (ii) the Company's customers fail to purchase or deliver the
contracted quantities of natural gas or NGLs, or (iii) the Company's OTC
counterparties fail to perform. To the extent that the Company engages in
hedging activities, it may be prevented from realizing the benefits of favorable
price changes in the physical market. However, it is similarly insulated
against decreases in such prices.
The Company has hedged a portion of its equity volumes of gas and NGLs in 1999,
particularly in the first quarter, at pricing levels approximating its 1999
operating budget. The Company's equity hedging strategy establishes a minimum
and maximum price to the Company while allowing market participation between
these levels. As of February 19, 1999, the Company had hedged approximately 75%
of its anticipated equity gas for 1999 at a weighted average NYMEX-equivalent
minimum price of $2.00 per Mcf, including approximately 80% of first quarter
anticipated equity volumes at a weighted average NYMEX-equivalent minimum price
of $2.00 per Mcf. Additionally, the Company has hedged approximately 75% of its
anticipated equity NGLs for 1999 at a weighted average composite Mont Belvieu
and West Texas Intermediate Crude-equivalent minimum price of $.23 per gallon.
At December 31, 1998, the Company had $1.1 million of losses deferred in
inventory that will be recognized primarily during the first quarter of 1999 and
are expected to be offset by margins from the Company's related forward fixed
price hedges and physical sales. At December 31, 1998, the Company had
unrecognized net gains of $3.8 million related to financial instruments that are
expected to be offset by corresponding unrecognized net losses from the
Company's obligations to sell physical quantities of gas and NGLs.
The Company enters into speculative futures, swap and option trades on a very
limited basis for purposes that include testing of hedging techniques. The
Company's policies contain strict guidelines for such trading including
predetermined stop-loss requirements and net open positions limits. Speculative
futures, swap and option positions are marked to market at the end of each
accounting period and any gain or loss is recognized in income for that period.
Net gains or losses from such speculative activities for the years ended
December 31, 1998 and 1997 were not material.
Natural Gas Derivative Market Risk
As of December 31, 1998, the Company held a notional quantity of approximately
370 Bcf of natural gas futures, swaps and options extending from January 1999 to
December 2000 with a weighted average duration of approximately four months.
This was comprised of approximately 178 Bcf of long positions and 192 Bcf of
short positions in such instruments. As of December 31, 1997, the Company held
a notional quantity of approximately 480 Bcf of natural gas futures, swaps and
options extending from January 1998 to December 1999 with a weighted average
duration of approximately four months. This was comprised of approximately 230
Bcf of long positions and 250 Bcf of short positions in such instruments.
Crude Oil and NGL Derivative Market Risk
As of December 31, 1998, the Company held a notional quantity of approximately
177 million gallons of NGL futures, swaps and options extending from January
1999 to December 1999 with a weighted average duration of approximately six
months. This was comprised of approximately 129 million gallons of long
positions and 48 million gallons of short positions in such instruments. As
41
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
of December 31, 1997, the Company held a notional quantity of approximately 148
million gallons of NGL futures, swaps and options extending from January 1998 to
December 1998 with a weighted average duration of approximately five months.
This was comprised of approximately 93 million gallons of long positions and 55
million gallons of short positions in such instruments.
As of December 31, 1998, the Company had sold 90,000 barrels per month of NYMEX
crude swaps for 1999 at an average price of $13.10 per barrel. In addition, the
Company had purchased 90,000 barrels per month of $15.00 per barrel NYMEX calls
for July 1999 through December 1999 settlement. The Company held no crude oil
futures, swaps or options for settlement beyond 1999.
As of December 31, 1998, the Company had purchased 200,000 barrels per month of
OPIS Mt. Belvieu monthly average settlement $0.210 per gallon puts to hedge a
portion of the Company's equity production of propane and butanes for 1999.
As of December 31, 1998, the Company had purchased 50,000 barrels per month of
OPIS Mt. Belvieu monthly average settlement $0.155 per gallon of purity ethane
puts to hedge a portion of the Company's equity production of ethane for 1999.
As of December 31, 1998, the Company held no NGL futures, swaps or options for
settlement beyond 1999.
As of December 31, 1998, the estimated fair value of the aforementioned crude
oil and NGL options held by the Company was approximately $315,000.
NOTE 5 - DEBT
- -------------
The following summarizes the Company's consolidated debt at the dates indicated
(000s):
December 31,
------------------
1998 1997
-------- --------
Master shelf and senior notes............ $269,381 $284,857
Variable rate revolving credit facility.. 235,500 156,500
-------- --------
Total long-term debt.................... $504,881 $441,357
======== ========
Revolving Credit Facility. The Company's variable rate Revolving Credit
Facility was restated and amended in May 1997. The Revolving Credit Facility is
with a syndicate of banks and provides for a maximum borrowing commitment of
$300 million, $235.5 million of which was outstanding at December 31, 1998. The
interest rate payable on the facility at December 31, 1998 was 6.2%. The Company
has reached an agreement with the agent bank on a term sheet for a restated
facility which will reflect the following changes. The restated Revolving Credit
Facility is with a syndicate of banks and will provide for an aggregate
borrowing commitment of $300 million consisting of a $100 million 364-day
Revolving Credit Facility ("Tranche A") and a five year $200 million Revolving
Credit Facility ("Tranche B"). The Revolving Credit Facility will bear interest
at certain spreads over the Eurodollar rate, at the Federal Funds rate plus .50%
or at the agent bank's prime rate. The Company will have the option to determine
which rate will be used. The Company also will pay a facility fee on the
commitment. The interest rate spreads and facility fee will be adjusted based on
the Company's debt to capitalization ratio and will range from .75% to 2.00%.
Pursuant to the Revolving Credit Facility, the Company will be required to
maintain a debt to capitalization ratio of not more than 60% through December
31, 2000 and of not more than 55% thereafter, and a senior debt to
capitalization ratio of not more than 40% beginning September 30, 1999 through
December 31, 2001 and of not more than 35% thereafter. The agreement also
requires a ratio of EBITDA to interest and dividends on preferred stock as of
the end of any fiscal quarter of not less than 1.35 to 1.0 beginning June 30,
1999 increasing to 3.25 to 1.0 by December 31, 2002. Tranche A and Tranche B
will be reduced on a pro rata basis to a total of $250 million by September 30,
1999. The Revolving Credit Facility is guaranteed and will be secured via a
pledge of the stock of the Company's significant subsidiaries. Documentation
reflecting this agreement is expected to be completed on or about the end of the
first quarter of 1999. The Company generally utilizes excess daily funds to
reduce any outstanding balances on the Revolving Credit Facility and associated
interest expense, and it intends to continue such practice.
42
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Master Shelf Agreement. In December 1991, the Company entered into a Master
Shelf agreement (as amended and restated, the "Master Shelf") with The
Prudential Insurance Company of America ("Prudential"). Amounts outstanding
under the Master Shelf agreement at December 31, 1998 are as indicated in the
following table (000s):
Interest Final
Issue Date Amount Rate Maturity Principal Payments Due
- ------------------- -------- ----- ------------------ -----------------------------------------------
October 27, 1992 $ 16,667 7.51% October 27, 2000 $8,333 on each of October 27, 1999 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
--------
$191,667
========
In March 1999, the Company reached an agreement on an amendment with Prudential
which will be effective as of January 1999 with the following provisions. The
Company will be 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 $300 million
plus 50% of consolidated net earnings earned from January 1, 1999 plus 75% of
the net proceeds of any equity offerings after January 1, 1999, and a debt to
capitalization ratio of not more than 60% through December 31, 2000 and of not
more than 55% thereafter. A senior debt to capitalization ratio will be
implemented, if and when, the Company issues subordinated debt. This amendment
also requires an EBITDA to interest ratio of not less than 1.75 to 1.0 beginning
March 31, 1999 increasing to a ratio of not less than 3.75 to 1.0 by March 31,
2002. Documentation reflecting this amendment is expected to be completed on or
about the end of the first quarter of 1999. In addition, under the existing
agreement, the Company is prohibited from declaring or paying dividends that in
the aggregate exceed the sum of $50 million plus 50% of consolidated net income
earned after June 30, 1995 (or minus 100% of a net loss), plus the aggregate net
cash proceeds received after June 30, 1995 from the sale of any stock. At
December 31, 1998, $51.5 million was available under this limitation. This
amount is expected to be reduced by approximately $ 14.9 million as a result of
the after-tax losses recognized on the sales of the Giddings and Katy
facilities. The Company presently intends to finance the $8.3 million payment
due on October 27, 1999 with amounts available under the Revolving Credit
Facility. The Master Shelf Agreement is guaranteed and will be secured via a
pledge of the stock of the Company's significant subsidiaries.
1995 Senior Notes. In 1995, the Company sold $42 million of Senior Notes
(the "1995 Senior Notes") to a group of insurance companies with an interest
rate of 8.16% per annum. In February 1999, the Company offered to prepay the
1995 Senior Notes at par. Note holders representing $15 million of the principal
amount outstanding on the 1995 Senior Notes accepted the Company's offer and
were paid in full in March 1999. These payments were financed by the Bridge Loan
and by amounts available under the Revolving Credit Facility. The remaining
principal amount outstanding of $27 million is due in a single payment in
December 2005. The 1995 Senior Notes are guaranteed and will be secured via a
pledge of the stock of the Company's significant subsidaries. The Company has
reached an agreement with the Note holders which provides for modification of
certain financial covenants on terms that will be no more restrictive than those
contained in the Master Shelf. Documentation reflecting this agreement is
expected to be completed on or about the end of the first quarter of 1999.
Effective January 1, 1999, the Company will pay an annual fee of no more than
.65% on the amounts outstanding on the Master Shelf and the 1995 Senior Notes.
This fee will continue until the Company has received an implied investment
grade rating on its senior secured debt.
1993 Senior Notes. In 1993, the Company sold $50 million of 7.65% Senior
Notes (the "1993 Senior Notes") to a group of insurance companies. Scheduled
annual principal payments of $7.1 million on the 1993 Senior Notes were made on
April 30 of 1997 and 1998. In February 1999, the Company offered to prepay the
1993 Senior Notes at par. Note holders representing approximately $33.5 million
of the total principal amount outstanding of $35.6 million accepted the
Company's offer and were paid in full in February 1999. These payments were
43
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
financed by a $37 million Bridge Loan. The Company intends to pay the remaining
outstanding principal of $2.1 million in the second quarter of 1999 with amounts
available under the Revolving Credit Facility.
Bridge Loan. In February 1999, in order to finance prepayments at par of
amounts outstanding on the 1993 and 1995 Senior Notes, the Company entered into
a Bridge Loan agreement in the amount of $37 million with its agent bank (the
"Bridge Loan"). The Bridge Loan bears interest at certain spreads over the
Eurodollar rate ranging from 1.75% at date of issuance to 2.75% at maturity. The
Bridge Loan may be prepaid in whole or in part at any time and matures on
October 31, 1999. The Company presently intends to finance the payment of the
Bridge Loan with amounts available under the Revolving Credit Facility, proceeds
from the sale of assets or proceeds from the issuance of public debt.
Covenant Compliance. At December 31, 1998, the Company was in compliance
with all covenants in its loan agreements. Taking into account all the covenants
contained in these agreements, the Company had approximately $64.5 million of
available borrowing capacity at December 31, 1998. In March 1999, the Company
successfully completed negotiations with its lenders for amendments to its
various financing facilities providing for financial flexibility and covenant
modifications. These amendments were needed given the depressed commodity
pricing experienced by the industry in general and the disappointing results the
Company has experienced at its Bethel Treating facility. There can be no
assurance that further amendments or waivers can be obtained in the future, if
necessary, or that the terms would be favorable to the Company. To strengthen
credit ratings and to reduce its overall debt outstanding, the Company will
continue to dispose of non-strategic assets (such as the Giddings and Katy
facilities) and investigate alternative financing sources (including the
issuance of public debt, project- financing, joint ventures and operating
leases).
Approximate future maturities of long-term debt at the date indicated, which do
not reflect the payments made in the first quarter of 1999, are as follows at
December 31, 1998 (000s):
1999.................................... $ 15,476
2000.................................... 15,477
2001.................................... 40,476
2002.................................... 250,976
2003.................................... 75,476
Thereafter.............................. 107,000
--------
Total................................. $504,881
========
NOTE 6 - FINANCIAL INSTRUMENTS
- ------------------------------
The estimated fair values of the Company's financial instruments have been
determined by the Company using available market information and valuation
methodologies. Considerable judgment is required to develop the estimates of
fair value; thus, the estimates provided herein are not necessarily indicative
of the amount that the Company could realize upon the sale or refinancing of
such financial instruments.
December 31, 1998 December 31, 1997
------------------ ------------------
Carrying Fair Carrying Fair
Value Value Value Value
-------- -------- -------- --------
(000s) (000s)
Cash and cash equivalents.. $ 4,400 $ 4,400 $ 19,777 $ 19,777
Trade accounts receivable.. 233,574 233,574 258,791 258,170
Accounts payable........... 245,315 245,315 326,696 326,696
Long-term debt............. 504,881 503,001 441,357 447,843
Risk management contracts.. $ - $ 2,281 $ - $ (2,189)
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.
44
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Long-term debt
The Company's long-term debt was primarily comprised of fixed rate facilities;
for this portion, fair market value was estimated using discounted cash flows
based upon the Company's current borrowing rates for debt with similar
maturities. The remaining portion of the long-term debt was borrowed on a
revolving basis which accrues interest at current rates; as a result, carrying
value approximates fair value of the outstanding debt.
Risk Management Contracts
Fair value represents the amount at which the instrument could be exchanged in a
current arms-length transaction.
NOTE 7 - INCOME TAXES
- ---------------------
The provision (benefit) for income taxes for the years ended December 31, 1998,
1997 and 1996 is comprised of (000s):
1998 1997 1996
--------- ----- -------
Current:
Federal............................. $ (5,696) $ 268 $ 1,152
State............................... - - -
-------- ----- -------
Total Current....................... (5,696) 268 1,152
-------- ----- -------
Deferred:
Federal............................. (31,272) 448 12,071
State............................... (1,450) 17 467
-------- ----- -------
Total Deferred...................... (32,722) 465 12,538
-------- ----- -------
Total tax provision (benefit).. $(38,418) $ 733 $13,690
======== ===== =======
Temporary differences and carryforwards which give rise to the deferred tax
liabilities (assets) at December 31, 1998 and 1997 are as follows (000s):
1998 1997
-------- --------
Property and equipment......................................... $133,054 $158,258
Differences between the book and tax basis of acquired assets.. 14,386 15,334
-------- --------
Total deferred income tax liabilities......................... 147,440 173,592
-------- --------
Alternative Minimum Tax ("AMT") credit carryforwards........... (21,128) (26,849)
Net Operating Loss ("NOL") carryforwards....................... (78,291) (66,000)
-------- --------
Total deferred income tax assets.............................. (99,419) (92,849)
-------- --------
Net deferred income taxes..................................... $ 48,021 $ 80,743
======== ========
45
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The differences between the provision (benefit) for income taxes at the
statutory rate and the actual provision (benefit) for income taxes for the years
ended December 31, 1998, 1997 and 1996 are summarized as follows (000s):
1998 % 1997 % 1996 %
-------- ---- ----- ----- ------- -----
Income tax (benefit) at statutory rate......... $(36,968) 35.0 $ 777 35.0 $14,570 35.0
State income taxes, net of federal benefit..... (1,450) 1.4 31 1.4 562 1.4
Permanent differences on asset write-downs..... - - - - - -
Reduction of deferred income taxes to reflect
adjustment in acquired NOL carryforward....... - - - - (900) (2.2)
Adjustment to prior year income taxes.......... - - - - (383) (.9)
Other.......................................... - - (75) (3.4) (159) (.4)
-------- ---- ----- ---- ------- ----
Total......................................... $(38,418) 36.4 $ 733 33.0 $13,690 32.9
======== ==== ===== ==== ======= ====
At December 31, 1998 the Company had NOL carryforwards for Federal and State
income tax purposes and AMT credit carryforwards for Federal income tax purposes
of approximately $215.4 million and $21.1 million, respectively. These
carryforwards expire as follows (000s):
Expiration Dates NOL AMT
--------------------------- -------- -------
2003....................... $ 170 $ -
2004....................... 413 -
2005....................... 943 -
2006....................... 478 -
2007....................... - -
2008....................... 12,179 -
2009....................... 56,308 -
2010....................... 59,857 -
2011....................... 16,221 -
2012....................... 39,033 -
2018....................... 29,807 -
No expiration.............. - 21,128
-------- -------
Total................. $215,409 $21,128
======== =======
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 were 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 appealed the decision to the Eighth Circuit Court of
Appeals. On September 1, 1998 the Court of Appeals reversed the summary
judgment entered for JN on an unjust enrichment theory and remanded the case to
the trial court for a determination on JN's contract claims. This case
46
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
has now been settled for an immaterial amount and will be dismissed with
prejudice. The Company believes that it has meritorious defenses to the remanded
claim and will vigorously defend 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.
Berco Resources, Inc. v. Amerada Hess Corporation and Western Gas
Resources, Inc., United States District Court,
District of Colorado, Civil Action No. 97-WM-1332
Berco Resources, Inc. ("Berco") is an independent producer and marketer of
natural gas and alleges it owns or has the right to produce and sell natural gas
in the Temple/Tioga Area in North Dakota. Berco alleges that Amerada Hess
engaged in unlawful monopolization under Section 2 of the Sherman Act and
Section 7 of the Clayton Act by acquiring natural gas gathering and producing
facilities owned by Western Gas. Berco alleges that the Company and Amerada
Hess have conspired, through the purchase and sale of the Company's facilities
in the Temple/Tioga Area, to create a monopoly affecting an appreciable amount
of interstate commerce in violation of Sections 1 and 2 of the Sherman Act.
Berco seeks an award against Amerada Hess and the Company of threefold the
amount of damages actually sustained by Berco, in an amount to be determined at
trial, and/or divestiture of the Company assets acquired by Amerada Hess, for an
order against the Company and Amerada Hess restraining and enjoining them from
violating the antitrust laws, and for costs, attorney fees and interest. The
Company believes that it has meritorious defenses to the claims and will
vigorously defend such claims. At the present time it is not possible to
predict the outcome of this litigation to estimate the amount of potential
damages.
Internal Revenue Service
The Internal Revenue Service ("IRS") has completed its examination of the
Company's tax returns for the years 1990 and 1991 and has proposed adjustments
to taxable income reflected in such tax 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 adjustments. The Company currently is protesting certain of these
proposed adjustments. In the opinion of management, any proposed adjustments for
the additional income taxes and interest that may result would not be material.
However, it is reasonably possible that the ultimate resolution could result in
an amount which differs materially from management's estimates.
Other
The Company is involved in various other litigation and administrative
proceedings arising in the normal course of business. In the opinion of
management, any liabilities that may result from these claims, will not,
individually or in the aggregate, have a material adverse effect on the
Company's financial position or results of operations.
NOTE 9 - BUSINESS SEGMENTS AND RELATED INFORMATION
- --------------------------------------------------
The Company operates in four principal business segments, as follows: Gas
Gathering and Processing, Producing Properties, Marketing and Transmission, and
these segments are separately monitored by management for performance against
its internal forecast and are consistent with the Company's internal financial
reporting package. These segments have been identified based upon the differing
products and services, regulatory environment and the expertise required for
these operations.
The Gas Gathering and Processing segment connects producers' wells to its
gathering systems for delivery to its processing or treating plants, processes
the natural gas to extract NGLs and treats the natural gas in order to meet
pipeline specifications. The residue gas and NGLs extracted at the processing
facilities are sold by the Marketing segment.
The activities of the Producing Properties segment includes the exploration and
development of certain oil and gas producing properties in basins where the
Company's facilities are located. The majority of the gas and oil produced from
these properties is sold by the Marketing segment.
47
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The Marketing segment buys and sells gas and NGLs nationwide and in Canada,
providing storage, transportation, scheduling, peaking and other services to a
variety of customers. In addition, this segment also markets gas and NGLs
produced by the Company's facilities. The operations associated with the
Company's Katy Facility are included in the Marketing segment as are the
Company's Canadian marketing operations (which is immaterial for separate
presentation).
The Transmission segment reflects the operations of the Company's MIGC and MGTC
pipelines. The majority of the revenue presented in this segment is derived
from transportation of residue gas.
The following table sets forth the Company's segment information as of and for
the years ended December 31, 1998, 1997 and 1996 (in 000s). Due to the
Company's integrated operations, the use of allocations in the determination of
business segment information is necessary. Intersegment revenues are valued at
prices comparable to those of unaffiliated customers.
Gas
Gathering
and Producing Trans- Eliminating
Processing Properties Marketing mission Corporate Entries Total
---------- ----------- ---------- -------- ---------- ---------- ------
Year ended December 31, 1998
Revenues from unaffiliated customers.... $ 38,613 $ 1,979 $2,067,561 $ 4,956 $ 1,091 $ 709 $2,114,909
Interest income......................... 1 - 45 - 29,531 (28,486) 1,091
Other, net.............................. 16,759 703 120 (16) - - 17,566
Intersegment sales...................... 425,895 24,878 81,384 12,365 - (544,522) -
-------- --------- ---------- ------- ------- --------- ----------
Total revenues.......................... 481,268 27,560 2,149,110 17,305 30,622 (572,299) 2,133,566
Product purchases....................... 330,369 1,368 2,126,621 - (3,386) (540,669) 1,914,303
Plant operating expense................. 65,318 2,437 6,999 11,167 2,694 (3,262) 85,353
Oil and gas exploration
and production expense................. - 7,466 155 - 233 142 7,996
-------- --------- ---------- ------- ------- --------- ----------
Operating profit........................ $ 85,581 $ 16,289 $ 15,335 $ 6,138 $31,081 $ (28,510) 125,914
======== ========= ========== ======= ======= ========= ==========
Depreciation, depletion and amortization 59,346
Interest expense........................ 33,616
Loss on the impairment of property and
equipment.............................. 108,447
Selling and administrative expense...... 30,128
----------
Income (loss) before income taxes....... $ (105,623)
==========
Identifiable assets..................... $577,782 $ 89,191 $ 118,661 $63,946 $17,780 $ - $ 867,360
======== ========= ========== ======= ======= ========= ==========
Year ended December 31, 1997
Revenues from unaffiliated customers.... $ 33,180 $ 1,189 $2,333,064 $ 5,457 $ 780 $ 3,871 $2,377,541
Interest income......................... 18 - 114 - 17,556 (16,460) 1,228
Other, net.............................. 1,094 4,727 132 - 538 - 6,491
Intersegment sales...................... 522,783 34,123 51,411 7,419 - (615,736) -
-------- -------- ----------- ------- -------- --------- ---------
Total revenues.......................... 557,075 40,039 2,384,721 12,876 18,874 (628,325) 2,385,260
Product purchases....................... 399,651 1,238 2,352,107 4,409 (2,558) (608,417) 2,146,430
Plant operating expense................. 63,749 2,912 6,597 6,394 1,814 (3,353) 78,113
Oil and gas exploration
and production expense................. 7 7,634 106 - 3 (36) 7,714
-------- -------- ----------- ------- --------- ---------- -----------
Operating profit........................ $ 93,668 $ 28,255 $ 25,911 $ 2,073 $ 19,615 $ (16,519) $ 153,003
======== ======== =========== ======= ========= ========== ===========
48
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Gas
Gathering
and Producing Trans- Eliminating
Processing Properties Marketing mission Corporate Entries Total
---------- ---------- ---------- -------- --------- --------- ----------
Year Ended December 31, 1997, cont.
Depreciation, depletion and amortization $59,248
Interest expense........................ 27,474
Loss on the impairment of property and
equipment.............................. 34,615
Selling and administrative expense...... 29,446
----------
Income (loss) before income taxes....... $ 2,220
==========
Identifiable assets..................... $698,899 $104,744 $ 121,305 $48,541 $13,723 $ - $ 987,212
======== ======== ========== ======= ======= ========= ==========
Year ended December 31, 1996
Revenues from unaffiliated customers.... $ 45,828 $ 764 $2,032,696 $ 5,187 $(2,785) $ 1,106 $2,082,796
Interest income......................... - - - - 14,316 (13,663) 653
Other, net.............................. 2,748 2,807 106 (6) 1,905 - 7,560
Intersegment sales...................... 506,356 33,041 38,377 6,249 - (584,023) -
-------- -------- ---------- ------- ------- --------- ----------
Total revenues.......................... 554,932 36,612 2,071,179 11,430 13,436 (596,580) 2,091,009
Product purchases....................... 390,890 334 2,033,190 4,551 (5,948) (578,866) 1,844,151
Plant operating expense................. 63,980 2,774 7,238 4,266 1,539 (6,681) 73,116
Oil and gas exploration
and production expense................. - 4,440 133 - - 483 5,056
-------- -------- ---------- ------- ------- --------- ----------
Operating profit........................ $100,062 $ 29,064 $ 30,618 $ 2,613 $17,845 $ (11,516) 168,686
======== ======== ========== ======= ======= ========= ==========
Depreciation, depletion and amortization 63,207
Interest expense 34,437
Loss on the impairment of property and
equipment.............................. -
Selling and administrative expense...... 29,411
----------
Income (loss) before income taxes....... $ 41,631
==========
Identifiable assets..................... $598,453 $119,132 $ 121,978 $36,110 $14,019 $ - $ 889,692
======== ======== ========== ======= ======= ========= ==========
NOTE 10 - EMPLOYEE BENEFIT PLANS
- --------------------------------
Profit Sharing Plan
A discretionary profit sharing plan (a defined contribution plan) exists for all
Company employees meeting certain service requirements. The Company may make
annual discretionary contributions to the plan as determined by the Board of
Directors and
49
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
provides for a match of 50% of employee contributions on the first 4% of
employee compensation contributed. Contributions are made to common/collective
trusts for which Fidelity Management Trust Company acts as trustee. The
discretionary contributions made by the Company were $1.9 million, $1.9 million
and $1.7 million, for the years ended December 31, 1998, 1997 and 1996,
respectively. The matching contributions were $668,000, $310,000 and $256,000
for the years ended December 31, 1998, 1997 and 1996, respectively.
Key Employees' Incentive Stock Option Plan and Non-Employee Director Stock
Option Plan
Effective April 1987, the Board of Directors of the Company adopted a Key
Employees' Incentive Stock Option Plan ("Key Employee Plan") and a Non-Employee
Director Stock Option Plan ("Directors' Plan") that authorize the granting of
options to purchase 250,000 and 20,000 shares of the Company's Common Stock,
respectively. Under the plans, each of these options became exercisable as to
25% of the shares covered by it on the later of January 1, 1992 or one year from
the date of grant, subject to the continuation of the optionee's relationship
with the Company, and became exercisable as to an additional 25% of the covered
shares on the later of each subsequent January 1 through 1995 or on each
subsequent date of grant anniversary, subject to the same condition. Each of
these plans will terminate on the earlier of February 6, 2000 or the date on
which all options granted under each of the plans have been exercised in full.
The Company has entered into agreements committing the Company to loan certain
employees an amount sufficient to exercise their options as each portion of
their options vests. The Company will forgive such loans and associated accrued
interest if the employee has been continuously employed by the Company for four
years after the date of each loan increment. In January 1999, the Board of
Directors voted to extend the maturity for all such loans for officers still
employed in January 1999, until January 2001. During 1996, under the terms of a
severance agreement, the Company extended the maturity date of one former
officer's loans to December 31, 2000. In addition, under the terms of a
severance agreement, the loans of a former officer are being forgiven over the
life of the original loan forgiveness schedule. As of December 31, 1998 and
1997, loans related to 81,250 and 112,500 shares of Common Stock, respectively,
totaling $870,000 and $1.2 million, respectively, were outstanding under these
terms.
1993 and 1997 Stock Option Plans
The 1993 Stock Option Plan ("1993 Plan") became effective on May 24, 1993 and
the 1997 Stock Option Plan ("1997 Plan") became effective on May 21, 1997 after
approvals by the Company's stockholders. Each plan is intended to be an
incentive stock option plan in accordance with the provisions of Section 422 of
the Internal Revenue Code of 1986, as amended. The Company has reserved
1,000,000 shares of Common Stock for issuance upon exercise of options under
each of the 1993 Plan and the 1997 Plan. The 1993 Plan and the 1997 Plan will
terminate on the earlier of March 21, 2003 and May 21, 2007, respectively, or
the date on which all options granted under each of the plans have been
exercised in full.
Under both of the plans, the Board of Directors of the Company determines and
designates from time to time those employees of the Company to whom options are
to be granted. If any option terminates or expires prior to being exercised,
the shares relating to such option are released and may be subject to reissuance
pursuant to a new option. The Board of Directors has the right to, among other
things, fix the price, terms and conditions for the grant or exercise of any
option. The purchase price of the stock under each option shall be the fair
market value of the stock at the time such option is granted. Under the 1993
Plan, options granted vest 20% each year on the anniversary of the date of grant
commencing with the first anniversary. Under the 1997 Plan, the Board of
Directors has the authority to set the vesting schedule from 20% per year to 33
1/3% per year. Under both plans, the employee must exercise the option within
five years of the date each portion vests.
$5.40 Stock Option Plan
In April 1987 and amended in February 1994, the Partnership adopted an employee
option plan ("$5.40 Plan") that authorized granting options to employees to
purchase 483,000 common units in the Partnership. Pursuant to the
Restructuring, the Company assumed the Partnership's obligation under the
employee option plan. The plan was amended upon the Restructuring to allow each
holder of existing options to exercise such options and acquire one share of
Common Stock for each common unit they were originally entitled to purchase.
The exercise price and all other terms and conditions for the exercise of such
options issued under the amended plan were the same as under the plan, except
that the Restructuring accelerated the time upon which certain options may be
exercised. All options under the plan were either exercised or forfeited on or
before May 31, 1997. The Company has entered into agreements committing the
Company to loan to certain employees an amount sufficient to exercise their
50
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
options, provided that the Company will not loan in excess of 25% of the total
amount available to the employee in any one year. In accordance with the
agreements, the Company forgave the majority of such loans and associated
accrued interest on July 2, 1997. Under the terms of a severance agreement, the
Company extended the maturity date of one former officer's loans to December 31,
2000. As of December 31, 1998 and 1997, loans related to 15,000 shares of Common
Stock in each year, respectively, totaling $81,000, were outstanding under these
terms.
The following table summarizes the number of stock options exercisable and
available for grant under the Company's benefit plans:
Key Employee Directors'
$5.40 Plan Plan Plan 1993 Plan 1997 Plan
---------- ------------ --------- --------- ---------
EXERCISABLE:
December 31, 1996....... 33,148 56,250 11,000 288,438 -
December 31, 1997....... - 75,000 12,250 448,171 -
December 31, 1998....... - 75,000 13,500 562,138 26,250
AVAILABLE FOR GRANT:
December 31, 1996....... - 31,250 1,250 4,734 -
December 31, 1997....... - 31,250 1,250 9,382 828,900
December 31, 1998....... - 31,250 1,250 96,609 763,400
51
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following table summarizes the stock option activity under the Company's
benefit plans:
Per Share Number of Shares
-------------------------------------------------------------
Price Key Employee Directors'
Range $5.40 Plan Plan Plan 1993 Plan 1997 Plan
--------------- ---------- ------------ --------- --------- ---------
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 - - - (46,591) -
-------- ------------ --------- -------- ---------
Balance 12/31/96........ 33,148 75,000 13,500 993,203 -
Granted................ 17.75 - 24.00 - - - 64,654 171,100
Exercised.............. 5.40 - 23.50 (32,077) - - (5,225) -
Forfeited or canceled.. 5.40 - 34.13 (1,071) - - (69,302) -
-------- ------------ --------- -------- ---------
Balance 12/31/97........ - 75,000 13,500 983,330 171,100
Granted................ 19.28 - - - 40,511 106,500
Exercised.............. 15.83 - - - (1,556) -
Forfeited or canceled.. $19.19 - $21.78 - - - (129,809) (41,000)
-------- ------------ --------- -------- ---------
Balance 12/31/98........ - 75,000 13,500 892,476 236,600
======== ============ ========= ======== =========
The following table summarizes the weighted average option exercise price
information under the Company's benefit plans:
Key Employee Directors'
$5.40 Plan Plan Plan 1993 Plan 1997 Plan
---------- ------------ ---------- --------- ---------
Balance 12/31/95......... $ 5.40 $ 30.23 $14.13 $25.11 -
Granted................ - - - 14.63 -
Exercised.............. 5.40 - - - -
Forfeited or canceled.. - - - 27.05 -
---------- ------------ ---------- --------- ---------
Balance 12/31/96......... 5.40 30.23 14.13 21.31 -
Granted................ - - - 19.71 19.63
Exercised.............. 5.40 - - 16.91 -
Forfeited or canceled.. 5.40 - - 25.54 -
---------- ------------ ---------- --------- ---------
Balance 12/31/97......... - 30.23 14.13 20.93 19.63
Granted................ - - - 19.28 11.69
Exercised.............. - - - 14.78 -
Forfeited or canceled.. - - - 21.97 19.16
---------- ------------ ---------- --------- ---------
Balance 12/31/98......... $ - $ 30.23 $14.13 $20.71 $16.15
52
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
SFAS No. 123 encourages companies to record compensation expense for stock-based
compensation plans at fair value. As permitted under SFAS No. 123, the Company
has elected to continue to measure compensation costs for such plans as
prescribed by APB No. 25. SFAS No. 123 requires pro forma disclosures for each
year a statement of operations is presented. Such information was only
calculated for the options granted under the 1993 Plan and the 1997 Plan as
there were no grants under any other plans. The weighted average fair value of
options granted under the 1993 Plan of $0.37, $10.54 and $10.18 for the years
ended December 31, 1998, 1997 and 1996, respectively, and the weighted average
fair value of options granted under the 1997 Plan of $1.00 and $12.66 for the
years ended December 31, 1998 and 1997, respectively, was estimated using the
Black-Scholes option-pricing model with the following assumptions:
1993 Plan 1997 Plan
-------------------------- -----------------
1998 1997 1996 1998 1997
------ ------- ------ ------ -------
Risk-free interest rate......... 5.3% 6.1% 6.35% 5.3% 6.1%
Expected life (in years)........ 5 6 7 6 10
Expected volatility............. 45% 42% 37% 45% 42%
Expected dividends (quarterly).. $ .05 $ .05 $ .05 $ .05 $ .05
Had compensation expense for the Company's 1998, 1997 and 1996 grants for stock-
based compensation plans been determined consistent with the fair value method
under SFAS No. 123, the Company's net income (loss), income (loss) attributable
to common stock, earnings (loss) per share of common stock and earnings (loss)
per share of common stock - assuming dilution would approximate the pro forma
amounts below (000s, except per share amounts):
1998 1997 1996
----------------------- ------------------------ ----------------------
As Reported Pro forma As Reported Pro forma As Reported Pro forma
------------ --------- ------------ ---------- ----------- ---------
Net income (loss).................... $(67,205) $(67,997) $ 1,487 $ 941 $27,941 $27,891
Net income (loss) attributable to
common stock........................ (77,644) (78,436) (8,952) (9,498) 17,502 17,452
Earnings (loss) per share of common
stock............................... (2.42) (2.44) (.28) (.30) .66 .66
Earnings (loss) per share of common
stock - assuming dilution.......... $ (2.42) $ (2.44) $ (.28) $ (.30) $ .66 $ .66
The 1993 Plan dictates that the options granted vest 20% each year on the
anniversary of the date of grant commencing with the first anniversary. The
Board of Directors has the authority to set the vesting schedule from 20% per
year to 33 1/3% per year for the 1997 Plan. All options granted in 1997 will
vest at the rate of 20% per year. As a result, no compensation expense, as
defined under SFAS No. 123, is recognized in the year options are granted. In
addition, the fair market value of the options at grant date is amortized over
this vesting period for purposes of calculating compensation expense.
53
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 11 - SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
- ----------------------------------------------------------------------
(UNAUDITED):
- ------------
Costs
The following tables set forth capitalized costs at December 31, 1998, 1997 and
1996 and costs incurred for oil and gas producing activities for the years ended
December 31, 1998, 1997 and 1996 (000s):
1998 1997 1996
-------- -------- --------
Capitalized costs:
Proved properties............................................... $110,090 $134,102 $140,871
Unproved properties............................................. 33,255 18,464 8,064
-------- -------- --------
Total............................................................ 143,345 152,566 148,935
Less accumulated depletion...................................... (58,994) (61,766) (58,548)
-------- -------- --------
Net capitalized costs............................................ $ 84,351 $ 90,800 $ 90,387
======== ======== ========
The Company's share of Redman Smackover's net capitalized costs.. $ - $ 3,845 $ 4,385
======== ======== ========
Costs incurred:
Acquisition of properties
Proved.......................................................... $ 2,174 $ 7,499 $ 242
Unproved........................................................ 22,633 10,457 909
Development costs................................................ 23,208 13,134 3,893
Exploration costs................................................ 4,177 1,322 2,581
-------- -------- --------
Total costs incurred............................................. $ 52,192 $ 32,412 $ 7,625
======== ======== ========
The Company's share of Redman Smackover's costs incurred......... $ 72 $ 236 $ 8
======== ======== ========
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, 1998,
1997 and 1996 are as follows (000s):
1998 1997 1996
-------- -------- --------
Revenues from sale of oil and gas:
Sales................................................ $ 2,592 $ 5,970 $ 1,821
Transfers............................................ 23,188 25,571 31,733
-------- -------- --------
Total.............................................. 25,780 31,541 33,554
Production costs...................................... (6,611) (6,384) (4,256)
Exploration costs..................................... (1,599) (1,439) (898)
Depreciation, depletion and amortization.............. (11,749) (11,549) (11,756)
Impairment of oil and gas properties.................. (16,528) (19,615) -
Income tax benefit (expense).......................... 3,690 2,792 (6,261)
-------- -------- --------
Results of operations................................. $ 7,017 $ (4,654) $ 10,383
======== ======== ========
The Company's share of Redman Smackover's operations.. $ 421 $ 1,265 $ 1,745
======== ======== ========
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
54
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
future net cash flows expected therefrom prepared by different engineers or by
the same engineers at different times may vary substantially. Results of
subsequent drilling, testing and production may cause either upward or downward
revisions of previous estimates. Further, the volumes considered to be
commercially recoverable fluctuate with changes in commodity prices and
operating costs. Any significant revision of reserve estimates could materially
adversely affect the Company's financial condition and results of operations.
The following table sets forth information for the years ended December 31,
1998, 1997 and 1996 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, 1995.......................................... 108,820 715
Revisions of previous estimates............................ (2,147) 286
Purchases of reserves in place............................. 2,372 -
Production................................................. (13,014) (158)
------- ------
December 31, 1996.......................................... 96,031 843
Revisions of previous estimates............................ (18,132) (74)
Extensions and discoveries................................. 113,251 191
Purchases of reserves in place............................. 34,588 -
Production................................................. (13,142) (154)
------- ------
December 31, 1997.......................................... 212,596 806
Revisions of previous estimates............................ 28,617 (200)
Extensions and discoveries................................. 43,248 66
Sales/Purchases of reserves in place, net.................. (31,020) -
Production................................................. (14,511) (117)
------- ------
December 31, 1998...................................... 238,930 555
======= ======
The Company's share of Redman Smackover's proved reserves:
December 31, 1996.......................................... 10,811 -
======= ======
December 31, 1997.......................................... 10,218 -
======= ======
December 31, 1998.......................................... - -
======= ======
Standardized Measures of Discounted Future Net Cash Flows
Estimated discounted future net cash flows and changes therein were determined
in accordance with SFAS No. 69, "Disclosures about Oil and Gas Producing
Activities." Certain information concerning the assumptions used in computing
the valuation of proved reserves and their inherent limitations are discussed
below. The Company believes such information is essential for a proper
understanding and assessment of the data presented.
Future cash inflows are computed by applying year end prices of oil and gas
relating to the Company's proved reserves to the year end quantities of those
reserves. Future price changes are considered only to the extent provided by
contractual arrangements, including futures contracts, in existence at year end.
The assumptions used to compute estimated future net revenues do not necessarily
reflect the Company's expectations of actual revenues or costs, nor their
present worth. In addition, variations from the expected production rate also
could result directly or indirectly from factors outside of the Company's
control, such as unintentional delays in development, changes in prices or
regulatory controls. The reserve valuation further assumes that all reserves
will be disposed of by production. However, if reserves are sold in place,
additional economic considerations could also affect the amount of cash
eventually realized.
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.
55
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Future income tax expenses are computed by applying the appropriate year end
statutory tax rates, with consideration of future tax rates already legislated,
to the future pre-tax net cash flows relating to the Company's proved oil and
gas reserves. Permanent differences in oil and gas-related tax credits and
allowances are recognized.
An annual discount rate of 10% was used to reflect the timing of the future net
cash flows relating to proved oil and gas reserves.
Information with respect to the Company's estimated discounted future cash flows
from its oil and gas properties for the years ended December 31, 1998, 1997 and
1996 is as follows (000s):
1998 1997 1996
--------- --------- ---------
Future cash inflows......................................................... $ 345,217 $ 352,491 $ 305,095
Future production costs..................................................... (108,457) (118,056) (54,306)
Future development costs.................................................... (46,066) (28,803) (1,728)
Future income tax expense................................................... (33,749) (32,614) (37,870)
--------- --------- ---------
Future net cash flows....................................................... 156,945 173,018 211,191
10% annual discount for estimated timing of cash flows...................... (59,068) (73,445) (100,474)
--------- --------- ---------
Standardized measure of discounted future net cash flows relating to
proved oil and gas reserves............................................... $ 97,877 $ 99,573 $ 110,717
========= ========= =========
The Company's share of Redman Smackover's standardized measure of
discounted future net cash flows relating to proved oil and gas reserves.. $ - $ 6,326 $ 5,684
========= ========= =========
Principal changes in the Company's estimated discounted future net cash flows
for the years ended December 31, 1998, 1997 and 1996 are as follows (000s):
1998 1997 1996
----------- ----------- ---------
January 1....................................... $ 99,573 $ 110,717 $ 81,762
Sales and transfers of oil and gas produced,
net of production costs....................... (19,170) (25,157) (29,298)
Net changes in prices and production costs
related to future production.................. 367 (146,968) 61,888
Development costs incurred during the period... 23,208 13,134 3,893
Changes in estimated future development costs.. (33,723) (26,875) (2,057)
Changes in extensions and discoveries.......... 23,336 158,314 -
Revisions of previous quantity estimates....... 35,438 (47,859) 2,554
Sales/Purchases of reserves in place, net...... (38,251) 47,867 5,266
Accretion of discount.......................... 9,957 11,072 8,176
Net change in income taxes..................... (1,134) 5,256 (19,484)
Other, net..................................... (1,724) 72 (1,983)
---------- --------- --------
December 31..................................... $ 97,877 $ 99,573 $110,717
========== ========= ========
56
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 12 - QUARTERLY RESULTS OF OPERATIONS (UNAUDITED):
- ------------------------------------------------------
The following summarizes certain quarterly results of operations (000s, except
per share amounts):
Earnings (Loss)
Per Share of
Net Earnings (Loss) Common Stock -
Operating Gross Income Per Share of Assuming
Revenues Profit (a) (Loss) Common Stock Dilution
---------- ---------- -------- -------------- ---------------
1998 quarter ended:
March 31....................................... $ 580,455 $ 37,019 $ 13,185 $ .33 $ .33
June 30........................................ 500,771 10,755 (2,645) (.16) (.16)
September 30................................... 516,259 8,307 (4,647) (.23) (.23)
December 31.................................... 536,081 10,487 (73,098)(c) (2.36) (2.36)
---------- --------- -------- ------ -------
$2,133,566 $ 66,568 $(67,205) $(2.42) $ (2.42)
========== ========= ======== ====== =======
1997 quarter ended:
March 31....................................... $ 635,538 $ 30,847 $ 10,608 $ .25 $ .25
June 30........................................ 463,575 15,508 878 (.05) (.05)
September 30................................... 555,888 20,757 4,997 .07 .07
December 31.................................... 730,259 26,643 (14,996)(b) (.55) (.55)
---------- --------- -------- ------ -------
$2,358,260 $ 93,755 $ 1,487 $ (.28) $ (.28)
========== ========= ======== ====== =======
(a) Excludes selling and administrative, interest and income tax expenses and
loss on the impairment of property and equipment.
(b) Includes a pre-tax, non-cash expense resulting from the evaluation of
property and equipment in accordance with SFAS No. 121 of $34.6 million.
(c) Includes a pre-tax, non-cash expense resulting from the evaluation of
property and equipment in accordance with SFAS No. 121 of $108.5 million.
57
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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,
1999 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 27 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).
58
10.1 Restated Profit-Sharing Plan and Trust Agreement of Western Gas
Resources, Inc. (Filed as exhibit 10.8 to Western Gas Resources,
Inc.'s Registration Statement on Form S-4, Registration No. 33-39588
dated March 27, 1991 and incorporated herein by reference).
10.2 Western Gas Resources, Inc. Key Employees' Incentive Stock Option Plan
(Filed as exhibit 10.13 to Western Gas Resources, Inc.'s Registration
Statement on Form S-4, Registration No. 33-39588 dated March 27, 1991
and incorporated herein by reference).
10.3 Registration Rights Agreement among Western Gas Resources, Inc., WGP,
Inc., Heetco, Inc., NV, Dean Phillips, Inc., Sauvage Gas Company and
Sauvage Gas Service, Inc. (Filed as exhibit 10.14 to Western Gas
Resources, Inc.'s Registration Statement on Form S-4, Registration No.
33-39588 dated March 27, 1991 and incorporated herein by reference).
10.4 Amendment No. 1 to Registration Rights Agreement as of May 1, 1991
between Western Gas Resources, Inc., Bill Sanderson, WGP, Inc., Dean
Phillips, Inc., Heetco, Inc., NV, Sauvage Gas Company and Sauvage Gas
Service, Inc. (Filed as exhibit 4.2 to Western Gas Resources, Inc.'s
Form 10-Q for the quarter ended June 30, 1991 and incorporated herein
by reference).
10.5 Second Amendment and First Restatement of Western Gas Processors, Ltd.
Employees' Common Units Option Plan (Filed as exhibit 10.6 to Western
Gas Resources, Inc.'s Registration Statement on Form S-1, Registration
No. 33-43077 dated November 14, 1991 and incorporated herein by
reference).
10.6 Agreement to provide loans to exercise key employees' common stock
options (Filed as exhibit 10.26 to Western Gas Resources, Inc.'s
Annual Report on Form 10-K for the fiscal year ended December 31, 1991
and incorporated herein by reference).
10.7 Agreement to provide loans to exercise employees' common stock options
(Filed as exhibit 10.27 to Western Gas Resources, Inc.'s Annual Report
on Form 10-K for the fiscal year ended December 31, 1991 and
incorporated herein by reference).
10.8 Note Purchase Agreement (without exhibits) dated as of April 1, 1993
by and between the Company and the Purchasers for $50,000,000, 7.65%
Senior Notes Due April 30, 2003 (Filed as exhibit 10.48 to Western Gas
Resources, Inc.'s Form 10-Q for the six months ended June 30, 1993 and
incorporated herein by reference).
10.9 General Partnership Agreement (without exhibits), dated August 10,
1993 for Westana Gathering Company by and between Western Gas
Resources -Oklahoma, Inc. (a subsidiary of the Company) and Panhandle
Gathering Company (Filed as exhibit 10.50 to Western Gas Resources,
Inc.'s Form 10-Q for the six months ended June 30, 1993 and
incorporated herein by reference).
10.10 Amendment to General Partnership Agreement dated August 10, 1993 by
and between Western Gas Resources -Oklahoma, Inc. (a subsidiary of the
Company) and Panhandle Gathering Company (Filed as exhibit 10.51 to
Western Gas Resources, Inc.'s Form 10-Q for the six months ended June
30, 1993 and incorporated herein by reference).
10.11 Amendment No. 1 to Note Purchase Agreement dated as of August 31, 1993
by and among the Company and the Purchasers (Filed as exhibit 10.61 to
Western Gas Resources, Inc.'s Form 10-Q for the nine months ended
September 30, 1993 and incorporated herein by reference).
10.12 Amendment No. 2 to Note Purchase Agreement dated as of August 31, 1994
by and among Western Gas Resources, Inc. and the Purchasers (Filed as
exhibit 10.68 to Western Gas Resources, Inc.'s Form 10-Q for the nine
months ended September 30, 1994 and incorporated herein by reference).
10.13 Amendment No. 3 to Note Purchase Agreement as of March 22, 1995 by and
among Western Gas Resources, Inc. and the Purchasers (Filed as exhibit
10.38 to Western Gas Resources, Inc.'s Form 10-Q for the three months
ended March 31, 1995 and incorporated herein by reference).
10.14 Form of Employment Agreement by and between Western Gas Resources,
Inc. and certain Executive Officers (Filed as exhibit 10.40 to
Western Gas Resources, Inc.'s Form 10-Q for the three months ended
March 31, 1995 and incorporated herein by reference).
59
10.15 Amendment No. 4 to Note Purchase Agreements as of July 14, 1995 by and
among Western Gas Resources, Inc. and the Purchasers (Filed as
exhibit 10.43 to Western Gas Resources, Inc.'s Form 10-Q for the six
months ended June 30, 1995 and incorporated herein by reference).
10.16 Second Amended and Restated Master Shelf Agreement effective January
31, 1996 by and between Western Gas Resources, Inc. and Prudential
Company of America (Filed as exhibit 10.49 to Western Gas Resources,
Inc.'s Form 10-K for the year ended December 31, 1995 and incorporated
herein by reference).
10.17 Fourth Amendment to First Restated Loan Agreement (Revolver) dated
November 29, 1995 by and among Western Gas Resources, Inc. and
NationsBank, as agent, and the Lenders (Filed as exhibit 10.51 to
Western Gas Resources, Inc.'s Form 10-K for the year ended December
31, 1995 and incorporated herein by reference).
10.18 Senior Note Purchase Agreement dated November 29, 1995 by and among
Western Gas Resources, Inc. and the Purchasers identified therein
(Filed as exhibit 10.52 to Western Gas Resources, Inc.'s Form 10-K for
the year ended December 31, 1995 and incorporated herein by
reference).
10.19 Loan Agreement dated May 30, 1997 among Western Gas Resources, Inc.
and NationsBank of Texas, N.A. as agent, Bank of America National
Trust and Savings Association as Co-agent and Certain Banks as Lenders
(Revolver) (Filed as exhibit 10.40 to Western Gas Resources, Inc.'s
Form 10-Q for the six months ended June 30, 1996 and incorporated
herein by reference).
11.1 Statement regarding computation of per share earnings.
12.1 Amended and Restated Bylaws of Western Gas Resources, Inc. adopted by
the Board of Directors on February 12, 1999.
12.2 Second Amendment dated February 17, 1999 to Credit Agreement by and
among Western Gas Resources, Inc. and NationsBank N.A., successor to
NationsBank of Texas, N.A., by merger, and the Lenders identified in
the Original Agreement dated May 30, 1997.
12.3 Offer to Acquire Notes dated February 12, 1999 by and between Western
Gas Resources, Inc. and CIGNA Investments, Inc., Royal Maccabees Life
Insurance Company, The Canada Life Assurance Company, and Canada Life
Insurance Company of America, original Purchasers under the Note
Purchase Agreement dated as of April 1, 1993 by and between Company
and Purchasers for $50,000,000, 7.65% Senior Notes due April 30, 2003.
12.4 Offer to Acquire Notes dated February 12, 1999 by and between Western
Gas Resources, Inc. and MONY Life Insurance Company, one of the
original Purchasers under the Note Purchase Agreement dated as of
November 29, 1995 by and between Company and Purchasers for
$42,000,000, 8.02% Senior Notes due December 1, 2005.
12.5 Loan Agreement dated February 17, 1999 by and among Western Gas
Resources, Inc. and NationsBank, N.A., for $37,000,000 Bridge Loan.
21.1 List of Subsidiaries of Western Gas Resources, Inc.
23.1 Consent of PricewaterhouseCoopers LLP
(b) Reports on Form 8-K:
A report on Form 8-K was filed on December 11, 1998 to announce that all
extensions of time for RIS Resources (USA) Inc.,a U.S. subsidiary of R.I.S.
Resource International Corp., have expired and that the companies are no
longer negotiating the sale of an interest in the Granger and Lincoln Road
Complex.
(c) Exhibits required by Item 601 of Regulation S-K. See (a) (3) above.
60
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 26, 1998.
WESTERN GAS RESOURCES, INC.
---------------------------
(Registrant)
By: /s/ BRION G. WISE
_________________________
Brion G. Wise
Chairman of the Board and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.
/s/ BRION G. WISE Chairman of the Board, Chief Executive Officer March 26, 1999
_____________________________
Brion G. Wise and Director
/s/ WALTER L. STONEHOCKER Vice Chairman of the Board and Director March 26, 1999
_____________________________
Walter L. Stonehocker
/s/ BILL M. SANDERSON Director March 26, 1999
_____________________________
Bill M. Sanderson
Director March 26, 1999
_____________________________
Richard B. Robinson
/s/ DEAN PHILLIPS Director March 26, 1999
_____________________________
Dean Phillips
/s/ WARD SAUVAGE Director March 26, 1999
_____________________________
Ward Sauvage
/s/ JAMES A. SENTY Director March 26, 1999
_____________________________
James A. Senty
/s/ JOSEPH E. REID Director March 26, 1999
_____________________________
Joseph E. Reid
/s/ WILLIAM J. KRYSIAK Vice President - Finance (Principal Financial and March 26, 1999
_____________________________
William J. Krysiak Accounting Officer)
61