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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark one)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED] FOR THE FISCAL YEAR ENDED DECEMBER
31, 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 0-3880
TOM BROWN, INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
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DELAWARE 95-1949781
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
P. O. BOX 2608
500 EMPIRE PLAZA BLDG.
MIDLAND, TEXAS 79701
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
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915-682-9715
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: None
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Common Stock, $.10 Par Value
Convertible Preferred Stock, $.10 Par Value
(TITLE OF CLASS)
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 [ ]
Indicate by check mark if disclosure of delinquent filers pursuant 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.
The aggregate market value of the Registrant's Common Stock held by
non-affiliates (based upon the last sale price of $11.875 per share as quoted on
the NASDAQ National Market System) on March 16, 1999 was approximately
$347,462,369.
As of March 16, 1999, there were 29,259,989 shares of Common Stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's definitive proxy statement for the 1999 Annual
Meeting of Stockholders to be held on May 20, 1999 are incorporated by reference
into Part III.
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TOM BROWN, INC.
FORM 10-K
CONTENTS
PAGE
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PART I
Item 1. Business.......................................................................... 3
Item 2. Properties........................................................................ 12
Item 3. Legal Proceedings................................................................. 14
Item 4. Submission of Matters to a Vote of Security Holders............................... 15
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters........................................................ 16
Item 6. Selected Financial Data........................................................... 18
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations........................................ 19
Item 7A. Quantitative and Qualitative Disclosures About Market Risk........................ 25
Item 8. Financial Statements and Supplementary Data....................................... 27
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure.................................... 60
PART III
Item 10. Directors and Executive Officers of the Registrant................................ 60
Item 11. Executive Compensation............................................................ 60
Item 12. Security Ownership of Certain Beneficial
Owners and Management...................................................... 60
Item 13. Certain Relationships and Related Transactions.................................... 60
PART IV
Item 14. Exhibits, Financial Statement Schedules
and Reports on Form 8-K.................................................... 61
Signatures.......................................................................................... 65
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PART I
ITEM 1. BUSINESS
GENERAL
Tom Brown, Inc. (the "Company") was organized as a Nevada corporation
in 1931 under the name Gold Metals Consolidated Mining Company. The name of the
Company was changed to Tom Brown Drilling Company, Inc. in 1968 and to Tom
Brown, Inc. in 1971. In April 1987, the Company changed its state of
incorporation from Nevada to Delaware. The executive offices of the Company are
located at 500 Empire Plaza, Midland, Texas 79701 and its telephone number at
that address is (915) 682-9715. Effective June 1, 1999, the Company will
relocate its headquarters and executive offices to Denver, Colorado. Unless the
context otherwise requires, all references to the "Company" include Tom Brown,
Inc. and its subsidiaries.
The Company is engaged primarily in the domestic exploration for, and
the acquisition, development, production, marketing, and sale of, natural gas
and crude oil. The Company's activities are conducted principally in the Wind
River and Green River Basins of Wyoming, the Piceance Basin of Colorado, the Val
Verde Basin of west Texas, the Permian Basin of west Texas and southeastern New
Mexico, and the East Texas Basin. The Company also, to a lesser extent, conducts
exploration and development activities in other areas of the continental United
States.
The Company's industry segments are (i) the exploration for, and the
acquisition, development and production of, natural gas and crude oil, (ii) the
marketing, gathering, processing and sale of natural gas, primarily through
Wildhorse Energy Partners, L.L.C. ("Wildhorse") and (iii) drilling gas and oil
wells, primarily through Sauer Drilling Company ("Sauer").
Except for its gas and oil leases with domestic governmental entities
and other third parties who enter into gas and oil leases or assignments with
the Company in the regular course of its business and options to purchase gas
and oil leases with the Shoshone and Northern Arapaho Tribes, the Company has no
material patents, licenses, franchises or concessions which it considers
significant to its gas and oil operations.
The nature of the Company's business is such that it does not maintain
or require a substantial amount of products, customer orders or inventory. The
Company's gas and oil operations are not subject to renegotiations of profits or
termination of contracts at the election of the federal government.
The Company has not been a party to any bankruptcy, receivership,
reorganization or similar proceeding, except in connection with reorganization
of Presidio Oil Company as described in Note 3 to Notes to Consolidated
Financial Statements.
BUSINESS STRATEGY
The Company's business strategy is to increase shareholder value through
the acquisition and development of long-lived gas and oil reserves in areas
where the Company has industry knowledge and operations expertise. The Company's
principal investments have been in natural gas prone basins, which the Company
believes will continue to provide the opportunity to accumulate significant
long-lived gas and oil reserves at attractive prices.
The Company's year-end acreage position was approximately 3,045,000
gross (1,690,000 net) acres (including options) located primarily in the Wind
River and Green River Basins of Wyoming, the Piceance Basin of Colorado, and the
Permian, Val Verde and East Texas Basins of Texas where the Company can utilize
its geological and technical expertise and its control of operations for the
further development and expansion of these areas. Approximately 88% of the net
acreage is undeveloped, giving the Company development drilling leverage to the
extent that gas prices increase. Additionally, by staying focused in it's core
basins, the Company continues to uncover more effective drilling and completion
techniques which can improve overall economic efficiency.
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The Company increased its reserves in 1998 over 1997 despite a 5% lower
gas price and a 34% lower oil price used in the estimate. Year-end proved
reserves were 406 billion cubic feet equivalent ("Bcfe"), a 16 Bcfe (4%)
increase over year-end 1997 reserves of 390 Bcfe. Since December 31, 1995, the
Company has increased proved reserves at a compounded annual growth rate of 29%,
or from 188 Bcfe to 406 Bcfe.
The Company increased its net gas production 13% in 1998 to 98 million
cubic feet per day (" Mmcfpd") and its overall production 8% to 115 million
cubic feet equivalent per day ("Mmcfepd"). This increase is primarily due to
development drilling in the Wind River, Piceance, and Val Verde Basins.
Through Wildhorse, the Company has continued to strengthen its ability
to control and market its production by accumulating natural gas gathering
assets and increasing its marketing efforts in its core areas of activity.
The Company plans to continue to selectively pursue acquisitions of gas
and oil properties in its core areas of activity and, in connection therewith,
the Company from time to time will be involved in evaluations of, or discussions
with, potential acquisition candidates. The consideration for any such
acquisition might involve the payment of cash and/or the issuance of equity or
debt securities. Due to current industry conditions, the Company plans to use
its financial liquidity to be a potential buyer in 1999.
Notwithstanding the Company's historical ability to implement the above
strategy, there can be no assurance that the Company will be able to
successfully implement its strategy in the future.
AREAS OF ACTIVITY
The following discussion focuses on areas the Company considers to be
its core areas of operations and those that offer the Company the greatest
opportunities for further exploration and development activities.
Wind River, Green River, and Piceance Basins
The Wind River and Green River Basins of Wyoming, and Piceance Basin of
Colorado account for a major portion of the Company's current and anticipated
exploration and development activities with approximately 70% of the Company's
proved reserves at December 31, 1998. The Company owns interests in 791
producing wells in these basins that averaged net daily production of 58 Mmcfe
for 1998. The Company has approximately 1,776,000 gross (1,125,000 net)
developed and undeveloped acres in these basins, including option acreage of
approximately 963,000 gross (549,000 net) undeveloped acres in the Wind River
Basin. The Company's interest in the leases and options to lease are subject to
the Company performing certain 3-D seismic operations and drilling certain
exploratory wells.
Although the Wind River Basin experienced limited natural gas
transportation capacity in the past, pipeline expansions and conversions have
worked to correct this capacity constraint. Additionally, the TransColorado
pipeline (which runs from the northern Piceance Basin to the San Juan Basin) is
now in service and has the capability to add 300 Mmcfpd in incremental capacity
out of the Rocky Mountain region.
Permian and Val Verde Basins
The Permian and Val Verde Basins accounted for approximately 17% of the
Company's proved reserves at December 31, 1998. The Company holds a 50% working
interest in approximately 39,000 gross acres and 50 producing wells in the Val
Verde Basin. The Company's share of production from this basin averaged 30
Mmcfepd of natural gas for 1998. The Permian Basin contains significant oil
reserves for the Company; however, year-end prices used in the reserve estimate
had a significant negative impact on the Company's proved reserves in this area.
The Company's properties in the Permian Basin are located primarily in the
Spraberry Field. The Company operates 319 wells and has approximately 28,000 net
developed and undeveloped acres in this basin.
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East Texas Basin
In January 1996, the Company began an exploration program in the Cotton
Valley Pinnacle Reef Trend of the East Texas Basin. At year-end 1998, the
Company controlled approximately 105,000 gross (55,000 net) acres in three
prospect areas. The Company participated in an exploratory dry hole in 1998 in
the Lake Tyler Prospect area. The Company continues to analyze and evaluate its
acreage position for further drilling activity.
BUSINESS DEVELOPMENTS
CURRENT DEVELOPMENTS IN THE GAS AND OIL BUSINESS
Acquisition of the Assets of Genesis Gas and Oil, L.L.C.
On October 21, 1997, the Company completed the acquisition of the assets
of Genesis Gas and Oil, L.L.C. ("Genesis"). The Genesis assets are located
primarily in the Piceance Basin of western Colorado and are principally operated
by the Company. The acquisition increased the Company's acreage position in the
Piceance Basin by approximately 32,000 net developed and 48,000 net undeveloped
acres. The Company's working interest doubled from 23% to 46% in 238 producing
wells and from 34% to 68% in 500 potential development locations from this
acquisition. The purchase price for these assets was approximately $35.5
million.
Acquisition of KN Production Company
The Company and KNE closed certain transactions on January 31, 1996
which resulted in (i) the Company's acquisition of all of the issued and
outstanding stock of KN Production Company ("KNPC"), a wholly owned subsidiary
of KNE, and (ii) Wildhorse being formed by the Company and KNE for the purpose
of providing gas gathering, processing, marketing, field and storage services,
(collectively the "KNPC Acquisition"). The price paid to KNE in connection with
the KNPC Acquisition was $36.25 million, of which $25 million was paid in the
form of 1.0 million shares of the Company's $1.75 Convertible Preferred Stock,
Series A (the "Preferred Stock") and the remaining $11.25 million was paid in
the form of 918,367 shares of the Company's Common Stock, based on a price per
share of $12.25. Additionally, the Company dedicated a significant amount of its
Rocky Mountain gas production to Wildhorse and KNE contributed gas marketing
contracts and gas storage assets located in western Colorado. The KNPC
Acquisition has been recorded using the purchase method of accounting.
As a result of the KNPC Acquisition, the Company acquired interests in
624 gross producing wells in Colorado and Wyoming, of which the Company became
operator of 308. The Company also acquired a natural gas storage facility in
western Colorado. The properties acquired by the Company included approximately
243,000 net undeveloped acres in Colorado, Wyoming, Kansas and Nebraska and
approximately 64,000 net developed acres located in Colorado and Wyoming.
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Acquisition of Presidio Oil Company
On December 23, 1996, the Company completed the acquisition of Presidio
Oil Company and its subsidiaries (the "Presidio Acquisition"), following the
issuance by the U.S. Bankruptcy Court, District of Delaware, on December 10,
1996, of an Order confirming Presidio Oil Company's reorganization under Chapter
11 of the U.S. Bankruptcy Code. The purchase price was approximately $206.6
million consisting of approximately $105 million in cash and 2.71 million shares
of the Company's Common Stock valued at $17.125 per share, plus the assumption
of certain liabilities. Such amount does not include 2.64 million shares of the
Company's Common Stock which were not issued due to the Company's ownership of
$56.15 million principal amount of Presidio Oil Company's Senior Gas Indexed
Notes (the "GINs"). The GINs were purchased in June 1995 for approximately $51
million as a strategic part of the Company's efforts to acquire Presidio Oil
Company. The Presidio Acquisition has been accounted for using the purchase
method. The cash portion of the Presidio Acquisition was funded by borrowings
under the Company's credit agreement with its bank lender. The assets acquired
consist of primarily proved oil and gas properties and approximately 865,000
gross (403,000 net) developed and undeveloped acres located primarily in
Wyoming, North Dakota, Oklahoma and Louisiana. The Wyoming properties are
concentrated in the Green River and Powder River Basins.
Joint Ventures
In December 1994 and December 1995, the Company and the Shoshone and
Northern Arapaho Tribes ("the Tribes") finalized the negotiations of six gas and
oil option agreements, which in addition to one option acquired earlier in 1993,
encompass approximately 663,000 gross acres (400,000 net acres) in the Wind
River Basin of Fremont County, Wyoming. The agreements grant the Company the
right to explore for and develop gas and oil reserves on the option acreage over
a ten-year period of time once the options are exercised.
In June 1996, the Company and the Tribes entered into an Exploration
License Agreement covering in excess of 300,000 gross acres in the Wind River
Basin of Wyoming. The agreement provided the Company the opportunity over the
next twelve months to enter into two Exploration Option Agreements covering a
minimum of 100,000 gross acres and a maximum of 150,000 gross acres each. The
Company has a 50% working interest in this agreement.
In October 1996, the Company and Louisiana Land and Exploration Company
(now Burlington Resources, Inc. ("Burlington")) announced the execution of a
letter of intent to form a joint exploration alliance in connection with the
Exploration License Agreement that the Company entered into with the Tribes. At
December 31, 1998 the Company had leases or options to lease approximately
963,000 gross (548,000 net) acres on the Wind River Indian Reservation. The
Company operates the jointly held interest and has a fifty percent (50%) working
interest. Burlington has a forty percent (40%) working interest with the
remaining ten percent (10%) being held by a third party in the areas covered
by the exploration license agreement. In the balance of the Company's acreage
on the Wind River Indian Reservation, the Company has a sixty percent (60%)
working interest, Burlington has a thirty percent (30%) working interest
and the remaining ten percent (10%) working interest is held by a third party.
In December 1996, the Company and American Exploration Company (now
Louis Dreyfus Natural Gas Corp. "LDNG")) announced the execution of a definitive
agreement to form an exploration joint venture that covers approximately 50,000
gross (40,000 net) acres of the Company's Lost Prairie and Lake Tyler Prospects
in Anderson, Cherokee and Smith Counties of east Texas located in the Cotton
Valley Pinnacle Reef Trend. In exchange for a forty percent (40%) working
interest ownership, LDNG has agreed to invest approximately $7.3 million for the
acquisition of land and a 3-D seismic survey. The Company retained the remaining
sixty percent (60%) working interest and serves as operator of the properties.
CURRENT DEVELOPMENTS IN THE MARKETING, GATHERING AND PROCESSING BUSINESS
Acquisition of Gathering and Processing Assets from Interenergy
Corporation
On December 19, 1997, KNE completed the acquisition of all of the assets
of Interenergy Corporation. The assets consist of gas gathering and processing
facilities located in Wyoming, Montana, North Dakota and South Dakota, as well
as a marketing division. KNE retained the marketing assets and Wildhorse
acquired the gathering
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and processing assets valued at $23.4 million. These assets consist of over 300
miles of pipeline and a processing plant. The Company, through its 45% share of
Wildhorse, will benefit from the acquisition as it develops its acreage in the
Big Horn Basin.
Acquisition of Gathering and Processing Assets from Williams Field
Services
In November 1996, Wildhorse completed the acquisition of the Williams
Field Services' gathering and processing assets in western Colorado and eastern
Utah. The acquired assets access existing Company production, as well as
approximately 240,000 acres of undeveloped leasehold held by the Company in the
Piceance Basin. Such assets will also provide gathering to undeveloped
third-party acreage throughout the Piceance and Uinta Basins. The assets
acquired include approximately 955 miles of natural gas gathering lines, two
processing plants, a carbon dioxide treatment plant and a dew point control
plant. The acquisition has provided a significant upstream position in an area
of the Rocky Mountains that has a great potential for developing additional
natural gas reserves and deliverability.
Acquisition of KN Production Company
An integral part of the KNPC Acquisition was the formation of Wildhorse,
which is owned fifty-five percent (55%) by KNE and forty-five percent (45%) by
the Company. The business and affairs of Wildhorse are managed by KNE under the
direction of an operating team consisting of two representatives appointed by
the Company and two representatives appointed by KNE.
The principal purpose of Wildhorse is to provide services related to
natural gas, natural gas liquids and other natural gas products, including
gathering, processing and storage services, marketing services and field
services.
CURRENT DEVELOPMENTS IN THE DRILLING BUSINESS
Acquisition of Sauer Drilling Company
On January 7, 1998, the Company completed the acquisition of W. E. Sauer
Companies L.L.C. of Casper Wyoming for approximately $8.1 million. The assets
purchased include five drilling rigs, tubular goods, a yard and related assets.
The Company operates the assets under the name Sauer Drilling Company and will
continue to serve the drilling needs of operators in the central Rocky Mountain
region in addition to drilling for the Company.
MARKETS
The Company's gas production has historically been sold under
month-to-month contracts with marketing companies. During 1998, there was a
significant amount of volatility in the prices received for natural gas. Monthly
closing gas prices as measured on the New York Mercantile Exchange ("NYMEX")
varied from a high of $2.36 per million British thermal unit ("Mmbtu") in July
1998 to a low of $1.67 per Mmbtu in September 1998. Additionally, the Company
produces approximately 50% of its gas production in the Rocky Mountain area
where the price of gas varied as compared to NYMEX prices from $.66 per Mmbtu
below NYMEX prices in July 1998 to no basis differential in September 1998.
The Company markets most of its oil production with independent
third-party resellers and refiners at market ("posted") prices. These posted
prices generally reflect the prices determined by the trading of West Texas
Intermediate ("WTI") oil futures contracts on the NYMEX, with adjustments due to
basis differential and for the quality of oil produced.
NYMEX prices for both gas and oil are influenced by seasonal demand,
levels of storage, production levels and a variety of political and economic
factors over which the Company has no control.
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PRODUCTION VOLUMES, UNIT PRICES AND COSTS
The following table sets forth certain information regarding the
Company's volumes of production sold and average prices received associated with
its production and sales of natural gas and crude oil for each of the years
ended December 31, 1998, 1997 and 1996.
Years ended December 31,
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1998 1997 1996
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Production Volumes:
Natural Gas (MMcf) 35,887 31,842 16,762
Crude Oil (MBbls) 1,027 1,159 545
Net Average Daily
Production Volumes:
Natural Gas (Mcf) 98,321 87,238 45,798
Crude Oil (Bbls) 2,814 3,175 1,489
Average Sales Prices:
Natural Gas (per Mcf) (2) $ 1.85 $ 2.18 $ 1.72
Crude Oil (per Bbl) $ 11.37 $ 18.02 $ 20.45
Average Production
Cost (per Mcfe) (1) $ .52 $ .56 $ .45
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(1) Includes production costs and taxes on production. (Mcfe means one
thousand cubic feet of natural gas equivalent, calculated on the basis of six
barrels of oil to one Mcf of gas.)
(2) Certain reclasses have been made to amounts reported in previous years
to conform to the 1998 presentation.
COMPETITION
The Company encounters strong competition from major oil companies and
independent operators in acquiring properties and leases for the exploration
for, and the development and production of, natural gas and crude oil.
Competition is particularly intense with respect to the acquisition of desirable
undeveloped gas and oil leases. The principal competitive factors in the
acquisition of undeveloped gas and oil leases include the availability and
quality of staff and data necessary to identify, investigate and purchase such
leases, and the financial resources necessary to acquire and develop such
leases. Many of the Company's competitors have financial resources, staffs and
facilities substantially greater than those of the Company. In addition, the
producing, processing and marketing of natural gas and crude oil is affected by
a number of factors which are beyond the control of the Company, the effect of
which cannot be accurately predicted.
The principal raw materials and resources necessary for the exploration
and development of natural gas and crude oil are leasehold prospects under which
gas and oil reserves may be discovered, drilling rigs and related equipment to
drill for and produce such reserves and knowledgeable personnel to conduct all
phases of gas and oil operations. The Company must compete for such raw
materials and resources with both major oil companies and independent operators.
Wildhorse encounters competition from other natural gas transportation
and marketing entities in the marketing of gas. Such competition may materially
affect the volumes and margins that Wildhorse may derive.
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EXECUTIVE OFFICERS OF THE COMPANY
The executive officers of the Company at March 10, 1999 were as follows:
Name Age Position with Company Since
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Donald L. Evans 52 Chairman of the Board and
Chief Executive Officer 1976
William R. Granberry 56 President and Director 1996
Thomas W. Dyk 45 Executive Vice President and
Chief Operating Officer 1998
Peter R. Scherer 42 Executive Vice President 1986
Damon Button 45 Executive Vice President and
Chief Financial Officer 1998
Richard B. Porter 43 Vice President - Land 1995
Bruce R. DeBoer 45 Vice President and General
Counsel/Secretary 1997
R. Kim Harris 42 Controller 1986
B. Jack Reed 49 Treasurer 1990
Each executive officer is elected annually by the Company's Board of
Directors to serve at the Board's discretion.
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EMPLOYEES
At December 31, 1998, the Company had 269 employees. None of the
Company's employees are represented by labor unions or covered by any collective
bargaining agreement. The Company considers its relations with its employees to
be satisfactory.
REGULATION
Regulation of Gas and Oil Production
Gas and oil operations are subject to various types of regulation by
state and federal agencies. Legislation affecting the gas and oil industry is
under constant review for amendment or expansion. Also, numerous departments and
agencies, both federal and state, are authorized by statute to issue rules and
regulations binding on the gas and oil industry and its individual members, some
of which carry substantial penalties for failure to comply. The regulatory
burden on the gas and oil industry increases the Company's cost of doing
business and, consequently, affects its profitability.
Gas Price Controls
Prior to January 1993, certain natural gas sold by the Company was
subject to regulation by the Federal Energy Regulatory Commission ("FERC") under
the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 ("NGPA"). The
NGPA prescribed maximum lawful prices for natural gas sales effective December
1, 1978. Effective January 1, 1993, natural gas prices were completely
deregulated and sales of the Company's natural gas are now made at market
prices. The majority of the Company's gas sales contracts either contain
decontrolled price provisions or already provide for market prices.
In April 1992, FERC issued Order 636, a rule designed to restructure the
interstate natural gas transportation and marketing system to remove various
barriers and practices that have historically limited non-pipeline gas sellers,
including producers, from effectively competing with pipelines. The
restructuring process was implemented on a pipeline-by-pipeline basis through
negotiations in individual pipeline proceedings. Since the issuance of Order
636, FERC has issued several orders making minor modifications to Order 636.
Because the restructuring requirements that emerge from the lengthy
administrative and judicial review process may be significantly different from
those currently in effect, and because implementation of the restructuring may
vary by pipeline, it is not possible to predict what, if any, effect the
restructuring resulting from Order 636 will have on the Company.
Oil Price Controls
Sales of crude oil, condensate and gas liquids by the Company are not
regulated and are made at market prices.
State Regulation of Gas and Oil Production
States in which the Company conducts its gas and oil activities regulate
the production and sale of natural gas and crude oil, including requirements for
obtaining drilling permits, the method of developing new fields, the spacing and
operation of wells and the prevention of waste of gas and oil resources. In
addition, most states regulate the rate of production and may establish maximum
daily production allowables for wells on a market demand or conservation basis.
Environmental Regulation
The Company's activities are subject to federal and state laws and
regulations governing environmental quality and pollution control. The existence
of such regulations has a material effect on the Company's operations
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but the cost of such compliance has not been material to date. However, the
Company believes that the gas and oil industry may experience increasing
liabilities and risks under the Comprehensive Environmental Response,
Compensation and Liability Act, as well as other federal, state and local
environmental laws, as a result of increased enforcement of environmental laws
by various regulatory agencies. As an "owner" or "operator" of property where
hazardous materials may exist or be present, the Company, like all others in the
petroleum industry, could be liable for fines and/or "clean-up" costs,
regardless of whether the Company was responsible for the release of any
hazardous substances.
Rocno Corporation, a wholly-owned subsidiary of the Company, was named
as a defendant in a Complaint filed by the United States on behalf of the
Environmental Protection Agency ("EPA") and has, along with approximately 117
other defendants, entered into a Consent Decree with the United States, pursuant
to which the defendant companies will carry out a clean-up plan. See Item 3,
Legal Proceedings.
Indian Lands
The Company's Muddy Ridge and Pavillion Fields are located on the Wind
River Indian Reservation. The Shoshone and Northern Arapaho Tribes regulate
certain aspects of the production and sale of natural gas and crude oil,
drilling operations, and the operation of wells and levy taxes on the production
of hydrocarbons. The Bureau of Indian Affairs and the Minerals Management
Service of the United States Department of the Interior perform certain
regulatory functions relating to operation of Indian gas and oil leases. The
Company owns interests in three leases in the Pavillion Field which were issued
pursuant to the provisions of the Act of August 21, 1916, for initial terms of
20 years each, with a preferential right by the lessee to renew the leases for
subsequent ten-year terms. The leases were renewed for ten-year terms in 1992,
effective as of June 1, 1993. These leases have been amended to provide for
incremental extensions of this lease term of up to an additional twelve years by
drilling and completing additional wells on each lease prior to June 2003.
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ITEM 2. PROPERTIES
GAS AND OIL PROPERTIES
The principal properties of the Company consist of developed and
undeveloped gas and oil leases. Generally, the terms of developed gas and oil
leaseholds are continuing and such leases remain in force by virtue of, and so
long as, production from lands under lease is maintained. Undeveloped gas and
oil leaseholds are generally for a primary term, such as five or ten years,
subject to maintenance with the payment of specified minimum delay rentals or
extension by production. The Company also has options to purchase undeveloped
gas and oil leaseholds on Shoshone and Northern Arapaho Tribal lands. Once
acreage on these lands is purchased, the undeveloped leaseholds are maintained
by the drilling of wells, minimum delay rentals or production. The leases must
be renewed after twenty years and the Company has a preferential right to
negotiate with the Tribes for such renewal.
TITLE TO PROPERTIES
As is customary in the gas and oil industry, the Company makes only a
cursory review of title to undeveloped gas and oil leases at the time they are
acquired by the Company. However, before drilling commences, the Company causes
a thorough title search to be conducted, and any material defects in title are
remedied prior to the time actual drilling of a well on the lease begins. The
Company believes that it has good title to its gas and oil properties, some of
which are subject to immaterial encumbrances, easements and restrictions. The
gas and oil properties owned by the Company are also typically subject to
royalty and other similar non-cost bearing interests customary in the industry.
The Company does not believe that any of these encumbrances or burdens
materially affects the Company's ownership or use of its properties.
ACREAGE
The following table sets forth the gross and net acres of developed and
undeveloped gas and oil leases held by the Company at December 31, 1998.
Excluded from the table are approximately 963,000 gross (549,000 net) acres in
Wyoming under gas and oil option agreements acquired from certain Indian tribes.
Developed Undeveloped
------------------------- -------------------------
Gross Net Gross Net
---------- ---------- ---------- ----------
Colorado 102,144 84,253 343,892 302,489
Kansas 1,961 1,563 1,802 1,613
Louisiana 12,326 3,981 12,956 3,617
Michigan 38 -- 303 121
Mississippi 756 362 4,791 597
Montana 4,751 718 178,317 39,463
Nebraska -- -- 41,725 32,146
New Mexico 15,977 3,981 2,440 2,036
North Dakota 920 1 7,159 515
Oklahoma 36,009 11,353 7,628 3,308
Texas 117,983 39,980 129,269 61,340
Utah -- -- 7,684 7,684
West Virginia 75,489 1,088 159,866 82,883
Wyoming 144,167 54,442 671,581 400,936
Other 360 80 10 2
---------- ---------- ---------- ----------
Total 512,881 201,802 1,569,423 938,750
========== ========== ========== ==========
"Gross" acres refer to the number of acres in which the Company owns a
working interest. "Net" acres refer to the sum of the fractional working
interests owned by the Company in gross acres.
12
13
GAS AND OIL RESERVES
Estimates of the Company's gas and oil reserves including future net
revenues and the present value of future net cash flows, were made by Ryder
Scott at December 31, 1998 and by Ryder Scott and Williamson Petroleum
Consultants, Inc. at December 31, 1997 and 1996, (both are independent petroleum
consultants), in accordance with guidelines established by the Securities and
Exchange Commission (the "SEC"). Estimates of gas and oil reserves and their
estimated values require numerous engineering assumptions as to the productive
capacity and production rates of existing geological formations and require the
use of certain SEC guidelines as to assumptions regarding costs to be incurred
in developing and producing reserves and prices to be realized from the sale of
future production. Accordingly, estimates of reserves and their value are
inherently imprecise and are subject to constant revision and change and should
not be construed as representing the actual quantities of future production or
cash flows to be realized from the Company's gas and oil properties or the fair
market value of such properties.
Certain additional unaudited information regarding the Company's
reserves, including the present value of future net cash flows, is set forth in
Note 14 of the Notes to Consolidated Financial Statements included herein.
The Company has no gas and oil reserves or production subject to
long-term supply or similar agreements with foreign governments or authorities.
Estimates of the Company's total proved gas and oil reserves have not
been filed with or included in reports to any federal authority or agency other
than the SEC.
PRODUCTIVE WELLS
The following table sets forth the gross and net productive gas and oil
wells in which the Company owned an interest at December 31, 1998.
Productive Wells
-----------------------------------------------
Gross Net
--------------------- ---------------------
Gas Oil Gas Oil
-------- -------- -------- --------
Colorado 462 63 218.68 31.95
Louisiana 50 38 13.39 13.93
New Mexico 34 28 7.27 12.15
North Dakota 6 5 2.13 3.49
Oklahoma 128 35 31.37 9.88
Texas 115 309 50.95 103.10
West Virginia 56 -- 18.39 --
Wyoming 441 151 147.35 42.59
Other 17 15 4.65 1.99
-------- -------- -------- --------
Total 1,309 644 494.18 219.08
======== ======== ======== ========
A "gross" well is a well in which the Company owns a working interest.
"Net" wells refer to the sum of the fractional working interests owned by the
Company in gross wells.
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14
GAS AND OIL DRILLING ACTIVITY
The following table sets forth the Company's gross and net interests in
exploratory and development wells drilled during the periods indicated.
Years ended December 31,
----------------------------------------------------------------------------------------------
1998 1997 1996
---------------------------- ---------------------------- ----------------------------
Type of well Gross Net Net % Gross Net Net % Gross Net Net %
- ------------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Exploratory
Gas 8 3.0 40 -- -- -- -- -- --
Oil -- -- -- -- -- -- -- -- --
Dry 7 4.5 60 7 3.7 100 5 2.8 100
------ ------ ------ ------ ------ ------ ------ ------ ------
15 7.5 100 7 3.7 100 5 2.8 100
Development
Gas 52 31.4 78 72 27.7 89 14 3.9 70
Oil 16 4.2 11 7 2.2 7 -- -- --
Dry 6 4.2 11 3 1.1 4 5 1.7 30
------ ------ ------ ------ ------ ------ ------ ------ ------
74 39.8 100 82 31.0 100 19 5.6 100
Total 89 47.3 89 34.7 24 8.4
====== ====== ====== ====== ====== ======
At December 31, 1998, 13 gross (5.8 net) development wells and 2 gross
(.6 net) exploration wells were in various stages of drilling and completion
in Texas and Wyoming.
OTHER PROPERTIES
The Company leases its home office facilities in Midland, Texas. The
lease covers approximately 32,000 square feet for a term of five years and
expires December 31, 2003.
The Company owns a 3,200 square foot office building located on a 2.94
acre tract in Midland, Texas. The facility is used primarily for storage of pipe
and oilfield equipment.
The Company also leases office facilities in Denver, Colorado. The lease
covers approximately 38,000 square feet for a term of 5 years and expires
January 31, 2003.
The Company has subleased approximately 41,000 square feet of leased
office space, which was obtained through the Presidio acquisition. Both the
lease and sublease will expire on March 31, 1999.
ITEM 3. LEGAL PROCEEDINGS
The Company is a defendant in several routine legal proceedings
incidental to its business, which the Company believes will not have a
significant effect on its consolidated financial position, results of operations
or cash flows.
In addition to routine legal proceedings incidental to the Company's
business, Rocno Corporation ("Rocno"), a wholly-owned subsidiary of the Company,
is a defendant in a Complaint filed by the United States of America which, among
other things, alleges that Rocno arranged for the disposal of "hazardous
materials" (within the meaning of the Comprehensive Environmental Response,
Compensation and Liability Act) in Waller County, Texas (the "Sheridan Superfund
Site"). In addition to Rocno, approximately 117 other companies were named as
defendants in the same matter with similar allegations by the Government of the
release by them of hazardous materials at the Sheridan Superfund Site. Effective
August 31, 1989, Rocno and thirty-six other defendants executed
14
15
the Sheridan Site Trust Agreement (the "Trust") for the purpose of creating a
trust to perform agreed upon remedial action at the Sheridan Superfund Site. In
connection with the establishment of the Trust, the parties to the Trust have
agreed to the terms of a Consent Decree entered December 3, 1991 in the United
States District Court, Southern District of Texas, Houston Division, Civil
Action No. H-91-3529, pursuant to which the defendants joining the Consent
Decree will carry out the clean-up plan prescribed by the Consent Decree. The
court has not yet approved the Consent Decree. The estimate of the total
clean-up cost is approximately $30 million. Under terms of the Trust, each party
is allocated a percentage of costs necessary to fund the Trust for clean-up
costs. Rocno's proportionate share of the estimated clean-up costs is 0.33% or
$99,000, of which $16,000 has been paid, and the remainder was accrued in the
Company's consolidated financial statements at December 31, 1998. If the
clean-up costs exceed the projected amount, Rocno will be required to pay its
pro rata share of the excess clean-up costs.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the Company's stockholders in the
fourth quarter of the year ended December 31, 1998.
15
16
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's Common Stock is traded in the over-the-counter market and
appears on the NASDAQ National Market System under the symbol "TMBR". The
following table sets forth the range of high and low closing quotations for each
quarterly period during the past two fiscal years as reported by NASDAQ National
Market System. The quotations are inter-dealer prices without retail mark-ups,
mark-downs or commissions and may not represent actual transactions.
Closing Sale Price
------------------
Quarter Ended High Low
------------- ---- ---
March 31, 1997 23 1/4 17
June 30, 1997 21 1/4 17 1/2
September 30, 1997 25 1/2 19 5/8
December 31, 1997 26 17 3/8
March 31, 1998 22 3/8 15 3/4
June 30, 1998 22 3/4 14 7/8
September 30, 1998 19 11 1/16
December 31, 1998 16 5/16 9 7/16
On March 16, 1999 the last sale price of the Company's Common Stock, as
reported by the NASDAQ National Market System, was $11.875 per share.
The transfer agent for the Company's Common Stock is Boston EquiServe,
L.P., Canton, Massachusetts.
On December 31, 1998, the outstanding shares of the Company's Common
Stock (29,259,989 shares) were held by approximately 2,300 holders of record.
The Company has never declared or paid any cash dividends to the holders
of Common Stock and has no present intention to pay cash dividends to the
holders of Common Stock in the future. Under the terms of the Company's Credit
Agreement, the Company is prohibited from paying cash dividends to the holders
of Common Stock without the written consent of the bank lenders. Additionally,
the Company's ability to declare and pay dividends on its Common Stock is
further restricted by the rights of the holder of the Series A Preferred Stock.
On December 23, 1996, the Company completed the acquisition of Presidio
Oil Company and its subsidiaries (collectively, "Presidio"), following the
issuance by the U.S. Bankruptcy Court, District of Delaware, on December 10,
1996, of an order confirming Presidio's reorganization under Chapter 11 of the
U.S. Bankruptcy Code. The Company issued 2,711,137 shares of its Common Stock to
creditors and shareholders of Presidio pursuant to Section 1145 of the United
States Bankruptcy Code.
On March 1, 1991, the Board of Directors adopted a Rights Plan designed
to help assure that all stockholders receive fair and equal treatment in the
event of a hostile attempt to take over the Company, and to help guard against
abusive takeover tactics. The Board of Directors declared a dividend of one
preferred share purchase right (a "Right") for each outstanding share of Common
Stock. The dividend was distributed on March 15, 1991 to the shareholders of
record on that date. Each Right entitles the registered holder to purchase, for
the $20 per share exercise price, shares of Common Stock or other securities of
the Company (or, under certain circumstances, of the acquiring person) worth
twice the per share exercise price of the Right.
16
17
The Rights will be exercisable only if a person or group acquires 20% or
more of the Company's Common Stock or announces a tender offer which would
result in ownership by a person or group of 20% or more of the Common Stock. The
date on which the above occurs is to be known as the ("Distribution Date"). The
Rights will expire on March 15, 2001, unless extended or redeemed earlier by the
Company.
At the time the Rights dividend was declared, the Board of Directors
further authorized the issuance of one Right with respect to each share of the
Company's Common Stock that shall become outstanding between March 15, 1991 and
the earlier of the Distribution Date or the expiration or redemption of the
Rights. Until the Distribution Date occurs, the certificates representing shares
of the Company's Common Stock also evidence the Rights. Following the
Distribution Date, the Rights will be evidenced by separate certificates.
The provisions described above may tend to deter any potential
unsolicited tender offers or other efforts to obtain control of the Company that
are not approved by the Board of Directors and thereby deprive the stockholders
of opportunities to sell shares of the Company's Common Stock at prices higher
than the prevailing market price. On the other hand, these provisions will tend
to assure continuity of management and corporate policies and to induce any
person seeking control of the Company or a business combination with the Company
to negotiate on terms acceptable to the then elected Board of Directors.
17
18
ITEM 6. SELECTED FINANCIAL DATA
The following tables set forth selected financial information for the
Company for each of the years shown.
The Company's historical results of operations have been materially
affected by the substantial increase in the Company's size as a result of the
Presidio Acquisition and the KNPC Acquisition. (See Note 3 to Notes to
Consolidated Financial Statements of the Company included elsewhere herein.)
Years ended December 31,
----------------------------------------------------------------------
1998 1997 1996 1995 1994
---------- ---------- ---------- ---------- ----------
(in thousands, except per share amounts)
Revenues (2) $ 131,330 $ 126,375 $ 65,915 $ 40,536 $ 29,028
========== ========== ========== ========== ==========
Net income (loss) attributable
to common stock (45,233) 6,860 6,263 5,785 (160)
========== ========== ========== ========== ==========
Weighted average number
of common shares outstanding (1)
Basic 29,251 25,110 21,116 16,292 15,464
========== ========== ========== ========== ==========
Diluted 29,251 26,407 22,525 16,887 16,053
========== ========== ========== ========== ==========
Net income (loss)
per common share (1)
Basic (1.55) .27 .30 .36 (.01)
========== ========== ========== ========== ==========
Diluted (1.55) .26 .28 .34 (.01)
========== ========== ========== ========== ==========
Total assets 441,882 450,926 406,374 164,174 115,092
========== ========== ========== ========== ==========
Long-term debt,
net of current
maturities 55,000 23,000 119,000 -- --
========== ========== ========== ========== ==========
Other Financial Data:
EBITDAX(3) 46,133 68,366 32,842 17,601 9,706
Net cash provided by operating activities
before changes in working capital(3) 43,544 59,652 31,902 12,235 10,488
Net cash provided by operating activities 69,240 47,600 29,114 10,127 8,708
Net cash used in investing activities (98,774) (86,672) (131,434) (72,200) (18,375)
Net cash provided by financing activities 25,667 25,105 117,842 47,908 311
- -------------------
(1) In accordance with Statement of Financial Accounting Standards ("SFAS")
No. 128 "Earnings per Share", net income per common share has been
restated for all periods presented.
(2) Certain reclasses have been made to amounts reported in previous years
to conform to the 1998 presentation.
(3) EBITDAX reflects income before income taxes, plus interest expense,
depreciation, depletion and amortization expense and exploration costs.
EBITDAX and net cash flows provided by operating activities before
changes in working capital are not measures determined pursuant to
generally accepted accounting principles ("GAAP") and are not intended
to be used in lieu of GAAP presentations of net income or cash flows
from operating activities. EBITDAX for 1998 and 1995 exclude a $51.3
million and an $8.4 million impairment of gas and oil properties, which
were non-cash charges.
The following tables set forth selected information for the Company's
gas and oil sales volumes and proved reserves for each of the years shown.
Years ended December 31,
------------------------------------------------------------
1998 1997 1996 1995 1994
-------- -------- -------- -------- --------
Volumes sold:
Gas (Mmcf) 35,887 31,842 16,762 10,585 7,087
Oil (Mbbls) 1,027 1,159 545 387 276
Proved reserves
at period end:
Gas (Mmcf) 372,022 347,104 359,167 163,303 180,306
Oil (Mbbls) 5,682 7,227 12,306 4,068 4,522
18
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
The Company's historical results of operations have been materially
affected by the substantial increase in the Company's size as a result of the
Presidio Acquisition (December, 1996) and the KNPC Acquisition (January, 1996).
(See Note 3 to Notes to Consolidated Financial Statements of the Company
included elsewhere herein.)
Revenues
During 1998, revenues from gas and oil production decreased 13% to $78.1
million as compared to $90.2 million in 1997. Such decrease in gas and oil
revenues was the result of a decrease in (i) average gas prices received by the
Company from $2.18 per Mcf to $1.85 per Mcf which decreased revenues by
approximately $10.4 million, (ii) average oil prices received from $18.02 per
barrel to $11.37 per barrel which decreased revenues by approximately $7.7
million and, (iii) oil sales volumes of 11% which decreased revenues by
approximately $1.5 million. Gas sales volumes increased 13% to 35.9 Bcf which
increased revenues by approximately $7.5 million. The increase in gas production
levels was primarily due to the Genesis Acquisition and successful drilling
results primarily in the Wind River Basin of Wyoming.
During 1997, revenues from gas and oil production increased 126% to
$90.2 million, as compared to $40.0 million in 1996. Such increase in gas and
oil revenues was the result of an increase in (i) average gas prices received by
the Company from $1.72 per Mcf to $2.18 per Mcf which increased revenues by
approximately $7.7 million, (ii) gas sales volumes of 90% which increased
revenues by approximately $32.8 million, and (iii) oil sales volumes of 113%
which increased revenues by approximately $11.0 million. A decrease in the
average oil prices from $20.45 to $18.02 reduced the revenues by approximately
$1.3. The increase in gas and oil volumes was primarily due to the Presidio
acquisition and development drilling.
19
20
The following table reflects the Company's revenues, average prices
received for gas and oil, and amount of gas and oil production in each of the
years shown:
Years ended December 31,
-----------------------------------------
1998 1997 1996
---------- ---------- ----------
(in thousands)
Revenues:
Natural gas sales $ 66,392 $ 69,332 $ 28,834
Crude oil sales 11,680 20,887 11,150
Marketing, gathering and processing 47,981 34,998 25,122
Drilling 4,561 -- --
Interest income and other 716 1,158 809
---------- ---------- ----------
Total revenues $ 131,330 $ 126,375 $ 65,915
========== ========== ==========
Net income (loss) attributable to
common stock $ (45,233) $ 6,860 $ 6,263
========== ========== ==========
Years ended December 31,
-----------------------------------------
1998 1997 1996
---------- ---------- ----------
Natural gas production sold (Mmcf) 35,887 31,842 16,762
Crude oil production (Mbbls) 1,027 1,159 545
Average natural gas sales price ($/Mcf) $ 1.85 $ 2.18 $ 1.72
Average crude oil sales price ($/Bbl) $ 11.37 $ 18.02 $ 20.45
In 1997 the Company sold the majority of its properties located in North
Dakota for $11.0 million. No gain or loss was recorded for the sale. The Company
had no significant property sales during 1998 or 1996.
Marketing, gathering and processing revenues increased 37% in 1998 as
compared to 1997 and 39% in 1997 as compared to 1996. Such increase is due
primarily to the acquisition of Interenergy and higher volumes of gas marketed
due to the Company's increased production and marketing of additional third
party gas.
Costs and Expenses
Expenses related to gas and oil production, production taxes, and
depreciation, depletion and amortization have increased in each of the last two
years due to increased production and revenue levels resulting from successful
drilling operations as well as the Genesis and Presidio Acquisitions. On an Mcfe
basis, the Company's costs decreased during the past year. Costs of gas and oil
production was $.35 per Mcfe in 1998, as compared to $.37 per Mcfe and $.29 per
Mcfe in 1997 and 1996, respectively. Taxes on gas and oil production, which are
generally calculated as a percentage of gas and oil sales, increased to 10% in
1998 as compared to 8% of gas and oil sales during 1997 and 1996. Such increase
from 1997 to 1998 was due to the increase of natural gas and oil produced in the
Wind River Basin in 1998 where the Company experiences additional production
taxes as compared to its other areas of operation.
The Company's depletion, depreciation and amortization rate increased on
an Mcfe basis to $1.06 per Mcfe for 1998 from $.93 per Mcfe in 1997 and $.76 per
Mcfe in 1996. The increase was the result of lower oil reserve estimates at
December 31, 1998 as a result of lower prices and higher cost reserve additions.
The Company also recorded a charge in 1998 of $51.3 million for the impairment
of gas and oil properties. (See Note 2 to the Notes to Consolidated Financial
Statements of the Company included elsewhere herein.)
20
21
The cost of gas sold in connection with the Company's marketing,
gathering and processing operations has increased in each of the last two years,
consistent with the increases in the associated revenues. The gross profit
decreased to a loss of $.5 million in 1998 as compared to income of $5.3 million
in 1997 and $4.6 million in 1996. The decrease is attributable to lower
gathering margins in 1998 and an increase in transportation costs relative to
market differentials.
Costs associated with exploration activities and impairments of
leasehold costs increased to $20.5 million in 1998 as compared to $14.6 million
in 1997 and $6.4 million in 1996. The increase was the result of an aggressive
exploratory drilling program during 1998 in which the Company began to more
fully explore for oil and gas on its large undeveloped acreage position.
General and administrative expenses increased in each of the last two
years as a result of the Company's significantly higher level of operations.
General and administrative expenses increased to $.17 per Mcfe in 1998 as
compared to $.13 and $.16 per Mcfe in 1997 and 1996, respectively. The Company
added personnel during 1998 which was the primary reason for the increase. In
1998, the Company reclassed certain general and administrative expenses that
were primarily related to the exploration and land departments to exploration
costs for the years ended 1998, 1997 and 1996. The amounts were approximately
$4.9 million, $4.3 million and $2.6 million respectively.
Interest expense decreased in 1998 as compared to 1997 as a result of a
lower level of debt outstanding during 1998. Interest expense increased in 1997
as compared to 1996 as a result of the debt incurred in connection with the
Presidio Acquisition in December 1996. A large portion of the debt was repaid in
October 1997 with the net proceeds of approximately $121.0 million from the sale
of 5.0 million shares of the Company's Common Stock.
The Company incurred a current tax liability in the amount of $380,000,
$403,000 and $290,000 in 1998, 1997 and 1996, respectively, as a result of the
application of the alternate minimum tax rules as provided under the Internal
Revenue Code. At December 31, 1998 the Company had a net operating loss
carryforward of approximately $31.3 million to offset potential taxable income.
The Company's net deferred tax asset was $32.0 million at December 31,
1998. A valuation allowance of approximately $2.6 million at December 31, 1998
was provided against the Company's net deferred tax assets based on management's
estimate of the recoverability of future tax benefits. The Company evaluated all
appropriate factors to determine the proper valuation allowance for
carryforwards, including any limitations concerning their use, the year the
carryforwards expire, the levels of taxable income necessary for utilization,
and tax planning strategies. In this regard, full valuation allowances were
provided for investment tax credit carryforwards and option plan compensation.
Based on its recent operating results and its expected levels of future
earnings, the Company believes it will, more likely than not, generate
sufficient taxable income to realize the benefit attributable to the net
operating loss carryforwards and other deferred tax assets for which valuation
allowances were not provided.
CAPITAL RESOURCES AND LIQUIDITY
Growth and Acquisitions
The Company continues to pursue opportunities which will add value by
increasing its reserve base and presence in significant natural gas areas, and
further developing the Company's ability to control and market the production of
natural gas. As the Company continues to evaluate potential acquisitions and
property development opportunities, it will benefit from its financing
flexibility and the leverage potential of the Company's overall capital
structure.
21
22
Capital and Exploration Expenditures
The Company's capital and exploration expenditures and sources of
financing for the years ended December 31, 1998, 1997 and 1996 are as follows:
1998 1997 1996
------ ------ ------
(in millions)
CAPITAL AND EXPLORATION EXPENDITURES:
Acquisitions:
Presidio $ -- $ -- $206.6
KNPC -- -- 36.3
Genesis -- 35.5 --
Interenergy -- 10.5 --
Williams Field Services -- -- 13.8
Sauer Drilling Company 8.1 -- --
Exploration costs 22.8 16.0 6.0
Development costs 49.3 33.8 13.2
Acreage 3.3 6.1 3.9
Gas gathering and processing 8.6 6.7 .7
Other 1.2 3.5 2.7
------ ------ ------
$ 93.3 $112.1 $283.2
====== ====== ======
FINANCING SOURCES:
Common stock issue(1) $ -- $121.7 $108.8
Preferred stock issue -- -- 25.0
Net long term bank debt 32.0 (96.0) 119.0
Advances from gas purchasers 24.3 -- --
Proceeds from sale of assets 1.9 12.6 .6
Cash flow from operations before
changes in working capital 43.5 59.7 31.9
Working capital and other (8.4) 14.1 (2.1)
------ ------ ------
$ 93.3 $112.1 $283.2
====== ====== ======
- ---------------
(1) Of the $108.8 million noted for 1996, 2.64 million shares of the Company's
Common Stock were not issued due to the Company's ownership of $56.15
million principal amount of Presidio Senior Gas Indexed Notes (the "GINS").
The GINS were purchased in June 1995 for approximately $51 million financed
primarily through a stock offering in 1995.
The Company anticipates capital expenditures of approximately $54
million in 1999, $39.6 million being allocated to exploration and development
drilling. The timing of most of the Company's capital expenditures is
discretionary and there are no material long-term commitments associated with
the Company's capital expenditure plans. Consequently, the Company is able to
adjust the level of its capital expenditures as circumstances warrant. The level
of capital expenditures by the Company will vary in future periods depending on
energy market conditions and other related economic factors.
Historically, the Company has funded capital expenditures and working
capital requirements with both internally generated cash, borrowings and stock
transactions. Net cash flow provided by operating activities increased to $69.2
million for 1998 as compared to $47.6 million and $29.1 million in 1997 and
1996, respectively. The increase in 1998 was due primarily to the receipt of
$24.3 million from gas purchasers as advances. These advances were for future
natural gas deliveries of 35,000 Mmbtu per day over a twelve month period
commencing January 1999. Net cash provided by operating activities in 1997
was primarily due to increases in gas prices received and higher gas production.
Advance From Gas Purchasers
The Company sold 35 Mmcfpd of gas for 1999 delivery, but was paid $24.3
million for the gas in the fourth quarter of 1998 as described in Note 6 of the
financial statements. The proceeds from the sale were used to repay bank debt.
As the gas is produced and delivered in 1999 without a corresponding payment
received, bank debt will increase more than would otherwise occur. During 1999,
the advance payment for gas included in current liabilities will be reduced and
bank debt increased due to the advanced sale transaction.
22
23
Bank Credit Facility
The Company's Credit Facility provides for a $100 million revolving line
of credit with a current borrowing base of $130 million. The amount of the
borrowing base may be redetermined as of December 31 and June 30 of each
calendar year at the sole discretion of the lender. A redetermination as of
December 31, 1998 has not yet been made.
At December 31, 1998, the aggregate outstanding balance under the Credit
Facility was $55 million, bearing interest at 6.1% per annum. The amount
available for borrowing under the Credit Facility at December 31, 1998 was $45
million. The Credit Facility contains certain financial covenants which require
the Company to maintain a minimum consolidated tangible net worth as well as
certain financial ratios. The Company was in compliance with the covenants
contained in the Credit Facility, except for the minimum consolidated tangible
net worth covenant for which the Company is required to maintain a minimum
consolidated tangible net worth of $350 million. As a result of the non-cash
charge of $51.3 million for the impairment of gas and oil properties, the
consolidated tangible net worth at December 31, 1998 was approximately $331
million. On March 15, 1999, the Company obtained a waiver of the net worth
covenant as of December 31, 1998 and amended the Credit Facility to reduce the
minimum consolidated tangible net worth covenant to $300 million. Borrowings
under the Credit Facility are unsecured and bear interest, at the election of
the Company, at (i) the greater of the agent bank's prime rate or the federal
funds effective rate, plus 0.50% or (ii) the agent bank's Eurodollar rate, plus
a margin ranging from 0.75% to 1.25%. See Note 4 to Notes to Consolidated
Financial Statements of the Company included elsewhere herein.
Public Offering
In October 1997, the Company sold 5,035,800 shares of its Common Stock
in a public offering. Net proceeds from the offering were approximately $121
million which were used to repay a majority of the Company's outstanding debt
and to fund the acquisition of all of the assets of Genesis.
Markets and Prices
Wildhorse, which was created to provide gathering, processing,
marketing, storage and field services to Rocky Mountain gas and oil producers,
will continue to pursue the construction or acquisition of gathering, processing
and storage areas of the Rocky Mountain region. During 1998, the Company's share
of Wildhorse's investments approximated $8.6 million for gas gathering and
processing assets. The Company (45 percent) and KNE (55 percent) jointly own
Wildhorse.
The Company has dedicated significant amounts of its Rocky Mountain gas
production to Wildhorse for gathering, processing and marketing. KNE contributed
gas marketing contracts and storage assets in western Colorado.
The Company's revenues and associated cash flows are significantly
impacted by changes in gas and oil prices. All of the Company's gas and oil
production is currently market sensitive as no amounts of the Company's future
gas and oil production have been sold at contractually specified prices except
for the advance from gas purchasers previously described. During 1998, the
average prices received for gas and oil by the Company were $1.85 per Mcf and
$11.37 per barrel, respectively, as compared to $2.18 Mcf and $18.02 per barrel
in 1997 and $1.72 per Mcf and $20.45 per barrel in 1996.
Year 2000
Year 2000 Issue. Many computer software systems were structured to use
a two-digit date field meaning that they will not be able to properly recognize
dates in the Year 2000. As a result, computer systems and software may need to
be upgraded to comply with such "Year 2000" requirements. Significant
uncertainty exists concerning the potential effects associated with such
compliance as systems that do not properly recognize such information could
generate erroneous data or cause a system to fail.
23
24
Compliance Program. In order to address the Year 2000 issue, the Company
appointed the Computer Information Systems department to assure that key
automated systems and related processors would remain functional through year
2000. The department addressed the project by reviewing the information
technology (IT) and non-information technology systems to determine whether they
were Year 2000 compliant. Also, the department prepared a formal questionnaire
for all significant suppliers, customers, and service providers to determine the
extent to which the Company was vulnerable to those third parties' failure to
remediate the Year 2000 problem.
Company State of Readiness. A review and assessment of the information
technology and non-information technology systems was completed as of December
31, 1998 and did not identify any material systems which are not Year 2000
compliant. In addition, the Company has received written assurances of Year 2000
compliance from approximately 75% of its operators and purchasers and 65% of its
vendors. The operators and purchasers who responded as being Year 2000
compliant represent 90% of the total dollar amount from that source to the
Company and the vendors who responded as being Year 2000 compliant represent
70%. The third party confirmation process is still ongoing. The Company believes
that any disruption caused from a third party's inability to be Year 2000
compliant will not be material to its operations.
Cost to Address Year 2000 Compliance Issues. The Company believes that
it will not be required to make any material expenditures to address the Year
2000 problem as it relates to its existing systems. To date, costs incurred to
address Year 2000 compliance have been internal in nature and have been charged
to income as incurred. Such costs have been funded from cash provided by
operating activities. However, uncertainty exists concerning the potential costs
and effects associated with any Year 2000 compliance, and the Company intends to
continue to make efforts to ensure that third parties with whom it has
relationships are Year 2000 compliant. The Computer Information Systems
department is not aware of any IT projects that have been delayed due to the
Year 2000 compliance program.
Risk of Non-Compliance and Contingency Plan. The goal of the Year 2000
project has been to ensure that all of the critical systems and processes which
are under the direct control of the Company remain functional. However, because
certain systems and processes may be interrelated with systems outside of the
control of the Company, there can be no assurance that all implementations will
be successful. The principal area of risk to the Company is thought to be gas
measurement control systems of pipeline volumes provided by third parties. A
likely worst case scenario is that despite the Company's efforts, there could be
failures of such systems which might cause disruption to the natural gas
delivery process. However, the Company believes that the risk of such occurrence
is low based upon its review and confirmation efforts concerning Year 2000
compliance with third party pipe lines. Accordingly, as part of the Year 2000
project, contingency plans will be developed to respond to any potential
failures as they may be identified. There can be no assurance that unexpected
Year 2000 compliance problems of either the Company or its vendors, customers
and service providers would not materially and adversely affect the Company's
business, financial condition or operating results. The Company will continue
throughout 1999, to consider the likelihood of a material business interruption
due to the Year 2000 issue.
Forward-Looking Statements and Risk
Certain statements in this report, including statements of the future
plans, objectives, and expected performance of the Company, are forward-looking
statements that are dependent on certain events, risks and uncertainties that
may be outside the Company's control which could cause actual results to differ
materially from those anticipated. Some of these include, but are not limited
to, economic and competitive conditions, inflation rates, legislative and
regulatory changes, financial market conditions, political and economic
uncertainties, future business decisions, and other uncertainties, all of which
are difficult to predict.
There are numerous uncertainties inherent in estimating quantities of
proven oil and gas reserves and in projecting future rates of production and
timing of development expenditures. The total amount or timing of actual future
production may vary significantly from reserves and production estimates. The
drilling of exploratory wells can involve significant risks including those
related to timing, success rates and cost overruns. Lease and rig availability,
complex geology and other factors can affect these risks. Future oil and gas
prices also could affect results of operations and cash flows.
Recent Accounting Pronouncements
In the first quarter of 1998, the Company adopted SFAS No. 130
"Reporting Comprehensive Income", which requires the display of comprehensive
income and its components in the financial statements. Comprehensive
24
25
income represents all non-stockholder related changes in equity of an entity
during the reporting period, including net non-stockholder related income and
charges directly to equity which are excluded from net income. For the years
ended December 31, 1998, 1997, and 1996 there are no material differences
between the Company's "traditional" and "comprehensive" net income.
In the fourth quarter of 1998, the Company adopted SFAS No. 131,
"Disclosures about Segments of an Enterprise and Related Information" which
establishes standards for the way public enterprises are to report information
about operating segments in annual financial statements and requires the
reporting of selected information about operating segments in interim financial
reports issued to shareholders. (See Note 10 to Notes to the Consolidated
Financial Statements.)
In June 1998, the Financial Accounting Standards Board issued SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities." The
Statement establishes accounting and reporting standards requiring that every
derivative instrument (including certain derivative instruments embedded in
other contracts) be recorded in the balance sheet as either an asset or
liability measured at its fair value. The Statement requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. SFAS No. 133 is effective for fiscal years
beginning after June 15, 1999 and cannot be applied retroactively. SFAS No. 133
must be applied to derivative instruments that were issued, acquired, or
substantially modified after December 31, 1997. The Company is evaluating SFAS
No. 133 and has not yet quantified the impact adopting the Statement will have
on its financial statements. However, SFAS No. 133 could increase volatility in
earnings and other comprehensive income (stockholders' equity) should the
Company continue to enter into transactions covered by the pronouncement.
In March 1998, the American Institute of Certified Public Accountants
(AICPA) issued Statement of Position (SOP) 98-1, "Accounting for the Costs of
Computer Software Developed or Obtained for Internal Use". The SOP provides
guidance with respect to accounting for the various types of costs incurred for
computer software developed or obtained for the Company's use. The Company is
required to and will adopt SOP 98-1 by the first quarter of fiscal 1999 and
believes that adoption will not have a significant effect on its consolidated
financial statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Company utilizes various financial instruments which inherently have
some degree of market risk. The primary sources of market risk include
fluctuations in commodity prices and interest rate fluctuations.
Price Fluctuations
The Company's results of operations are highly dependent upon the prices
received for oil and natural gas production. Accordingly, in order to increase
the financial flexibility and to protect the Company against commodity price
fluctuations, the Company may, from time to time in the ordinary course of
business, enter into non-speculative hedge arrangements, commodity swap
agreements, forward sale contracts, commodity futures, options and other similar
agreements relating to natural gas and crude oil.
In connection with an advance payment for future natural gas deliveries,
the Company entered into three gas price swap contracts with third parties under
which the Company became a fixed price payor for 35,000 Mmbtu per day for a
twelve month period commencing January 1999 at a weighted average price of $2.02
per Mmbtu. At December 31, 1998, the estimated fair value of the open gas price
swap contracts was an unrealized loss of $1.2 million.
Interest Rate Risk
At December 31, 1998, the Company had $55 million outstanding under its
credit facility at an average interest rate of 6.1%. Borrowings under the
Company's credit facility bear interest, at the election of the Company, at (i)
the greater of the agent bank's prime rate or the federal funds effective rate,
plus 0.50% or (ii) the agent bank's
25
26
Eurodollar rate, plus a margin ranging from 0.75% to 1.00%. As a result, the
Company's annual interest cost in 1999 will fluctuate based on short-term
interest rates. Assuming no change in the amount outstanding during 1999, the
impact on interest expense of a ten percent change in the average interest rate
would be approximately $336,000. As the interest rate is variable and is
reflective of current market conditions, the carrying value approximates the
fair value.
26
27
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements Page
------------------------------------------ ----
Report of Independent Public Accountants 28
Consolidated Balance Sheets,
December 31, 1998 and 1997 29
Consolidated Statements of Operations,
Years ended December 31, 1998, 1997 and 1996 31
Consolidated Statements of Changes in Stockholders' Equity,
Years ended December 31, 1998, 1997 and 1996 32
Consolidated Statements of Cash Flows,
Years ended December 31, 1998, 1997 and 1996 33
Notes to Consolidated Financial Statements 35
27
28
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Tom Brown, Inc.:
We have audited the accompanying consolidated balance sheets of Tom Brown, Inc.
(a Delaware corporation) and subsidiaries as of December 31, 1998 and 1997, and
the related consolidated statements of operations, changes in stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1998. 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 in accordance with generally accepted auditing
standards. Those standards 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. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Tom Brown, Inc. and
subsidiaries as of December 31, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Houston, Texas
February 25, 1999
(except with respect to
the matter discussed in
Note 4, as to which the
date is March 15, 1999)
28
29
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
---------------------
1998 1997
-------- --------
(in thousands)
CURRENT ASSETS:
Cash and cash equivalents $ 2,670 $ 6,537
Accounts receivable 32,390 40,949
Inventories 532 365
Deferred income taxes 8,585 --
Other 260 271
-------- --------
Total current assets 44,437 48,122
-------- --------
PROPERTY AND EQUIPMENT, AT COST:
Gas and oil properties, successful
efforts method of accounting 387,336 500,561
Gas gathering and processing and other plant 51,561 42,924
Other 20,340 9,031
-------- --------
Total property and equipment 459,237 552,516
Less: Accumulated depreciation,
depletion and amortization 92,232 160,480
-------- --------
Net property and equipment 367,005 392,036
-------- --------
OTHER ASSETS:
Deferred income taxes, net 23,429 2,606
Other assets 7,011 8,162
-------- --------
Total other assets 30,440 10,768
-------- --------
$441,882 $450,926
======== ========
See accompanying notes to consolidated financial statements.
29
30
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND STOCKHOLDERS' EQUITY
December 31,
--------------------------
1998 1997
---------- ----------
(in thousands)
CURRENT LIABILITIES:
Accounts payable $ 23,124 $ 32,367
Accrued expenses 4,754 7,332
Advances from gas purchasers 24,529 --
Note payable - current -- 5,168
---------- ----------
Total current liabilities 52,407 44,867
---------- ----------
BANK DEBT 55,000 23,000
---------- ----------
OTHER NON-CURRENT LIABILITIES 2,725 6,661
---------- ----------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Convertible preferred stock, $.10 par value
Authorized 2,500,000 shares;
Outstanding 1,000,000 shares with a
liquidation preference of $25,000,000 100 100
Common Stock, $.10 par value
Authorized 40,000,000 shares;
Outstanding 29,259,989 shares and
29,210,354 shares, respectively 2,926 2,921
Additional paid-in capital 431,082 430,502
Accumulated deficit (102,358) (57,125)
---------- ----------
Total stockholders' equity 331,750 376,398
---------- ----------
$ 441,882 $ 450,926
========== ==========
See accompanying notes to consolidated financial statements.
30
31
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Years ended December 31,
------------------------------------------
1998 1997 1996
---------- ---------- ----------
(in thousands, except per share amounts)
REVENUES:
Gas and oil sales $ 78,072 $ 90,219 $ 39,984
Marketing, gathering and processing 47,981 34,998 25,122
Drilling 4,561 -- --
Interest income and other 716 1,158 809
---------- ---------- ----------
Total revenues 131,330 126,375 65,915
---------- ---------- ----------
COSTS AND EXPENSES:
Gas and oil production 14,522 14,336 5,771
Taxes on gas and oil production 7,512 7,437 3,258
Cost of gas sold 48,442 29,734 20,496
Drilling operations 4,367 -- --
Exploration costs 17,274 13,222 6,040
Impairments of leasehold costs 3,215 1,350 331
General and administrative 7,139 5,152 3,217
Depreciation, depletion and amortization 44,575 36,230 15,140
Impairment of gas and oil properties 51,344 -- --
Interest expense 4,301 5,920 389
---------- ---------- ----------
Total costs and expenses 202,691 113,381 54,642
---------- ---------- ----------
Income (loss) before income taxes (71,361) 12,994 11,273
Income tax benefit (provision)
Current (1,611) (1,026) (571)
Deferred 29,489 (3,358) (2,767)
---------- ---------- ----------
Net income (loss) (43,483) 8,610 7,935
Preferred stock dividends (1,750) (1,750) (1,672)
---------- ---------- ----------
Net income (loss) attributable to common stock $ (45,233) $ 6,860 $ 6,263
========== ========== ==========
Weighted average number of common shares outstanding:
Basic 29,251 25,110 21,116
========== ========== ==========
Diluted 29,251 26,407 22,525
========== ========== ==========
Net income (loss) per common share:
Basic $ (1.55) $ .27 $ .30
========== ========== ==========
Diluted $ (1.55) $ .26 $ .28
========== ========== ==========
See accompanying notes to consolidated financial statements.
31
32
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
Additional Total
Preferred Common Paid-in Accumulated Stockholders'
Stock Stock Capital Deficit Equity
---------- ---------- ---------- ---------- ----------
(in thousands)
BALANCE AS OF
DECEMBER 31, 1995 $ -- $ 2,018 $ 224,889 $ (70,248) $ 156,659
Stock issuance for
KNPC Acquisition 100 92 36,058 -- 36,250
Stock options exercised -- 9 510 -- 519
Common stock issuance for
Presidio Acquisition -- 271 46,157 -- 46,428
Stock issuance costs -- -- (5) -- (5)
Option plan compensation -- -- 22 -- 22
Net income -- -- -- 7,935 7,935
Preferred stock dividends -- -- -- (1,672) (1,672)
---------- ---------- ---------- ---------- ----------
BALANCE AS OF
DECEMBER 31, 1996 100 2,390 307,631 (63,985) 246,136
Stock options exercised -- 24 1,558 -- 1,582
Common stock issuance -- 507 121,705 -- 122,212
Stock issuance costs -- -- (392) -- (392)
Net income -- -- -- 8,610 8,610
Preferred stock dividends -- -- -- (1,750) (1,750)
---------- ---------- ---------- ---------- ----------
BALANCE AS OF
DECEMBER 31, 1997 100 2,921 430,502 (57,125) 376,398
Stock options exercised -- 5 580 -- 585
Net loss -- -- -- (43,483) (43,483)
Preferred stock dividends -- -- -- (1,750) (1,750)
---------- ---------- ---------- ---------- ----------
BALANCE AS OF
DECEMBER 31, 1998 $ 100 $ 2,926 $ 431,082 $ (102,358) $ 331,750
========== ========== ========== ========== ==========
See accompanying notes to consolidated financial statements.
32
33
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31,
------------------------------------
1998 1997 1996
-------- -------- --------
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $(43,483) $ 8,610 $ 7,935
Adjustments to reconcile net income
to net cash provided by
operating activities:
Depreciation, depletion and amortization 44,575 36,230 15,140
(Gain) loss on sales of assets 27 (19) (267)
Impairment of gas and oil properties 51,344 -- --
Deferred taxes (29,408) 259 2,701
Option plan compensation -- -- 22
Exploration costs 17,274 13,222 6,040
Impairments of leasehold costs 3,215 1,350 331
-------- -------- --------
43,544 59,652 31,902
Changes in operating assets
and liabilities:
Decrease (increase) in
accounts receivable 8,559 (7,869) (15,408)
(Increase) decrease in inventories (167) (63) 75
Decrease in
other current assets 11 618 220
Increase (decrease) in accounts
payable and accrued expenses (4,451) (2,847) 9,919
Decrease (increase) in other
assets, net (2,785) (1,891) 2,406
Advances from gas purchasers 24,529 -- --
-------- -------- --------
Net cash provided by operating
activities $ 69,240 $ 47,600 $ 29,114
-------- -------- --------
(continued)
See accompanying notes to consolidated financial statements.
33
34
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31,
------------------------------------------
1998 1997 1996
---------- ---------- ----------
(in thousands)
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sales of assets $ 1,870 $ 12,635 $ 593
KNPC and Presidio Acquisitions -- -- (95,529)
Capital and exploration expenditures (93,274) (106,805) (38,862)
Changes in accounts payable and accrued
expenses for capital expenditures (7,370) 7,498 2,364
---------- ---------- ----------
Net cash used in investing activities (98,774) (86,672) (131,434)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of common stock -- 121,665 --
Borrowings of long-term bank debt 106,000 27,000 119,000
Repayments of long-term bank debt (74,000) (123,000) --
Repayments of note payable, current (5,168) -- --
Preferred stock dividends (1,750) (1,750) (1,672)
Proceeds from exercise of stock options 585 1,582 519
Stock issuance costs -- (392) (5)
---------- ---------- ----------
Net cash provided by financing activities 25,667 25,105 117,842
---------- ---------- ----------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS (3,867) (13,967) 15,522
CASH AND CASH EQUIVALENTS AT
BEGINNING OF YEAR 6,537 20,504 4,982
---------- ---------- ----------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 2,670 $ 6,537 $ 20,504
========== ========== ==========
Cash paid during the year for:
Interest $ 3,985 $ 6,027 $ 136
Income taxes 308 429 190
See accompanying notes to consolidated financial statements.
34
35
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
For the years ended December 31, 1998, 1997 and 1996
(1) NATURE OF OPERATIONS
Tom Brown, Inc. and its wholly-owned subsidiaries ("the Company") is an
independent energy company engaged in the domestic exploration for, and the
acquisition, development, marketing, production and sale of, natural gas and
crude oil. The Company's industry segments are (i) the exploration for, and the
acquisition, development, production, and sale of, natural gas and crude oil,
(ii) the marketing, gathering and processing of natural gas, primarily through
Wildhorse Energy Partners, L. L. C. ("Wildhorse") and (iii) drilling gas and oil
wells, primarily through Sauer Drilling Company ("Sauer"). All of the Company's
operations are conducted in the United States. The Company's operations are
presently focused in the Wind River and Green River Basins of Wyoming, the
Piceance Basin of Colorado, the Val Verde Basin of west Texas, the Permian Basin
of west Texas and southeastern New Mexico, and east Texas. The Company also, to
a lesser extent, conducts exploration and development activities in other areas
of the continental United States.
Substantially all of the Company's production is sold under
market-sensitive contracts. The Company's revenue, profitability and future rate
of growth are substantially dependent upon the price of, and demand for, oil,
natural gas and natural gas liquids. Prices for natural gas and oil are subject
to wide fluctuation in response to relatively minor changes in their supply and
demand as well as market uncertainty and a variety of additional factors that
are beyond the control of the Company. These factors include the level of
consumer product demand, weather conditions, domestic and foreign governmental
regulations, the price and availability of alternative fuels, political
conditions in foreign countries, the foreign supply of natural gas and oil and
the price of foreign imports and overall economic conditions. The Company is
affected more by fluctuations in natural gas prices than oil prices because a
majority of its production (85 percent in 1998 on a volumetric equivalent basis)
is natural gas.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation and Basis of Presentation
The accompanying consolidated financial statements include the accounts
of the Company. The Company's proportionate share of assets, liabilities,
revenues and expenses associated with certain interests in a gas and oil
partnership and the Company's 45% ownership in Wildhorse are consolidated within
the accompanying financial statements. All significant intercompany accounts and
transactions have been eliminated. Certain reclassifications have been made to
amounts reported in previous years to conform to the 1998 presentation.
Inventories
Inventories consist of pipe and other production equipment. Inventories
are stated at the lower of cost (principally first-in, first-out) or estimated
net realizable value.
Property and Equipment
The Company accounts for its natural gas and crude oil exploration and
development activities under the successful efforts method of accounting. Under
such method, costs of productive exploratory wells, development dry holes and
productive wells and undeveloped leases are capitalized. Gas and oil lease
acquisition costs are also capitalized. Exploration costs, including personnel,
geological and geophysical expenses and delay rentals for gas and oil leases,
are charged to expense as incurred. Exploratory drilling costs are initially
capitalized, but charged to expense if and when the well is determined not to
have found reserves in commercial quantities.
35
36
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
Maintenance and repairs are charged to expense; renewals and betterment
are capitalized to the appropriate property and equipment accounts. Upon
retirement or disposition of assets, the costs and related accumulated
depreciation are removed from the accounts with the resulting gains or losses,
if any, reflected in results of operations.
Unproved properties with significant acquisition costs are assessed
quarterly on a property-by-property basis and any impairment in value is charged
to expense. Unproved properties whose acquisition costs are not individually
significant are aggregated, and the portion of such costs estimated to be
nonproductive, based on historical experience, is amortized over the average
holding period. If the unproved properties are determined to be productive, the
related costs are transferred to proved gas and oil properties.
The Company reviews its gas and oil properties for impairment whenever
events and circumstances indicate a decline in the recoverability of their
carrying value. In the fourth quarter of 1998, due to the decline in oil and
natural gas prices, the Company estimated the expected future cash flows of its
gas and oil properties and compared such future cash flows to the carrying
amount of the gas and oil properties to determine if the carrying amount was
recoverable. For certain gas and oil properties, the carrying amount exceeded
the estimated undiscounted future cash flows; thus, the Company adjusted the
carrying amount of the respective oil and gas properties to their fair value.
The factors used to determine fair value included, but were not limited to,
estimates of proved reserves, future commodity pricing, future production
estimates, anticipated capital expenditures, and a discount rate commensurate
with the Company's internal rate of return on its gas and oil properties. As a
result, the Company recognized a noncash pretax charge of $51.3 million related
to the impairment of gas and oil properties in the fourth quarter of 1998. There
were no impairments of gas and oil properties in 1997 or 1996.
The provision for depreciation, depletion and amortization of oil and
gas properties is calculated on a basin-by-basin basis using the
unit-of-production method. Included in such calculations are estimated future
dismantlement, restoration and abandonment costs, net of estimated salvage
values.
Other property and equipment is recorded at cost and depreciated using
the straight-line method based on estimated useful lives.
Natural Gas Revenues
The Company utilizes the accrual method of accounting for natural gas
revenues whereby revenues are recognized as the Company's entitlement share of
gas is produced based from its working interests in the properties. The Company
records a receivable (payable) to the extent it receives less (more) than its
proportionate share of gas revenues. The Company had net gas balancing
liabilities of approximately $1.4 million and $3.0 million associated with
approximately 1.4 billion and 2.7 billion cubic feet ("Bcf") of gas at December
31, 1998 and 1997 respectively.
Derivative Financial Instruments
In order to increase financial flexibility and to protect the Company
against commodity price fluctuations, the Company may, from time to time in the
ordinary course of business, enter into non-speculative hedge arrangements,
commodity swap agreements, forward sale contracts, commodity futures, options
and other similar agreements relating to natural gas and crude oil.
Financial instruments designated as hedges are accounted for on the
accrual basis with gains and losses
36
37
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
being recognized based on the type of contract and exposure being hedged.
Gains and losses on natural gas and crude oil swaps designated as hedges of
anticipated transactions, including accrued gains or losses upon maturity or
termination of the contract, are deferred and recognized in income when the
associated hedged commodities are produced. In order for natural gas and crude
oil swaps to qualify as a hedge of an anticipated transaction, the derivative
contract must identify the expected date of the transaction, the commodity
involved, and the expected quantity to be purchased or sold among other
requirements. In the event that a hedged transaction does not occur, future
gains and losses, including termination gains or losses, are included in the
income statement when incurred.
Income Taxes
The Company provides for income taxes using the liability method under
which deferred income taxes are recognized for the tax consequences of
"temporary differences" by applying enacted statutory tax rates applicable to
future years to differences between the financial statement carrying amounts and
the tax bases of existing assets and liabilities. The effect on deferred taxes
of a change in tax laws or tax rates is recognized in income in the period such
changes are enacted.
Stock-Based Compensation
The Company accounts for employee stock-based compensation using the
intrinsic value method prescribed by Accounting Principles Board (APB) Opinion
No. 25, "Accounting for Stock Issued to Employees" and related interpretations.
Reference is made to Note 8, "Benefit Plans" for a summary of the pro forma
effect of Statement of Financial Accounting Standards ("SFAS") No. 123,
"Accounting for Stock Based Compensation", in the Company's results of
operations for 1998, 1997 and 1996.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and the
disclosure of contingent assets and liabilities at the date of the financial
statements. Such estimates and assumptions also affect the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from those estimates. Significant estimates with regard to these financial
statements include the estimate of proved oil and gas reserve volumes and the
related present value of estimated future net revenues to be received therefrom
(see Note 14), as well as the valuation allowance for deferred taxes (see Note
5).
Net Income Per Common Share
The Company adopted SFAS No. 128, "Earnings Per Share" in 1997. Under
SFAS No. 128, primary earnings per share ("Primary EPS") has been replaced by
basic earnings per share ("Basic EPS"), and fully diluted earnings per share
("Fully Diluted EPS") has been replaced by diluted earnings per share ("Diluted
EPS"). Basic EPS differs from Primary EPS in that it only includes the weighted
average impact of outstanding shares of the Company's common stock (i.e., it
excludes the dilutive effect of common stock equivalents such as the Preferred
Stock, as described in Note 7, stock options, etc.). Diluted EPS is
substantially similar to Fully Diluted EPS. The provision of SFAS No. 128
resulted in the retroactive restatement for all periods of previously reported
net income per common share figures.
37
38
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
Basic net income per share is calculated by dividing net income
attributable to common stock by the weighted average number of common shares
outstanding during the period including the weighted average impact of the
shares of common stock issued during the year from the date of issuance.
Diluted net income per share calculations also include the dilutive
effect of stock options which are convertible into common stock. In 1998,
approximately 545,000 stock options and 1,666,000 convertible preferred shares
were excluded from the net loss per common share calculation, as the effect
would have been antidilutive.
The following is a reconciliation of the numerators and denominators
used in the calculation of basic and diluted net income per common share for the
years ended December 31, 1998, 1997 and 1996:
1998 1997 1996
----------------------------- ---------------------------- ----------------------------
Per Per Per
Net Share Net Share Net Share
Income Shares Amount Income Shares Amount Income Shares Amount
-------- -------- -------- -------- -------- -------- -------- -------- --------
(in thousands except per share amounts)
Basic EPS:
Net Income (loss) Attributable
to Common Stock
and Share Amounts $(45,233) 29,251 $ (1.55) $ 6,860 25,110 $ .27 $ 6,263 21,116 $ .30
Dilutive Securities:
Stock Options -- -- -- -- 1,297 -- -- 1,409 --
-------- -------- -------- -------- -------- -------- -------- -------- --------
Diluted EPS:
Net Income (loss) Attributable
to Common Stock and
Assumed Share Amounts $(45,233) 29,251 $ (1.55) $ 6,860 26,407 $ .26 $ 6,263 22,525 $ .28
======== ======== ======== ======== ======== ======== ======== ======== ========
Consolidated Statements of Cash Flows
The Company considers investments purchased with an original maturity of
three months or less to be cash equivalents. In connection with the acquisition
of Interenergy in December 1997, Wildhorse assumed $11.5 million in debt, $5.2
million net to the Company. (See notes 3 and 4.) During the year ended December
31, 1996 the Company (i) issued 1.0 million shares of Preferred Stock and .9
million shares of Common Stock in connection with the KNPC Acquisition (see Note
3), and (ii) issued 2.71 million shares of the Company's Common Stock and
converted its $51 million investment in Presidio GINs, purchased in June 1995,
into equity ownership, both in connection with the Presidio Acquisition (see
Note 3). Insofar as such transactions are non-cash, they are not reflected in
the Consolidated Statements of Cash Flows.
Comprehensive Income
In the first quarter of 1998, the Company adopted SFAS No. 130
"Reporting Comprehensive Income", which requires the display of comprehensive
income and its components in the financial statements. Comprehensive income
represents all non-shareholder related changes in equity of an entity during
the reporting period, including net income and charges directly to equity
which are excluded from net income. For the years ended December 31, 1998,
1997, and 1996 there are no differences between the Company's "traditional"
and "comprehensive" net income.
38
39
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
(3) ACQUISITIONS AND DIVESTITURES
Acquisition of Sauer Drilling Company
In January 1998, the Company completed the acquisition of W. E. Sauer
Companies L.L.C. of Casper, Wyoming for approximately $8.1 million. The assets
purchased include five drilling rigs, tubular goods, a yard and related assets.
The Company operates the assets under the name Sauer Drilling Company and serves
the drilling needs of operators in the central Rocky Mountain region, in
addition to drilling for the Company.
Acquisition of Gathering and Processing Assets by Wildhorse
In December 1997, KNE completed the acquisition of all of the assets of
Interenergy Corporation, ("Interenergy"). The assets consist of gas gathering
and processing facilities located in Wyoming, Montana, North Dakota and South
Dakota, as well as a marketing division. KNE retained the marketing assets and
Wildhorse acquired the gathering and processing assets valued at $23.4 million.
The Company's share of this purchase was approximately $10.5 million. These
assets consist of over 300 miles of pipeline and a processing plant. The Company
will benefit from the acquisition as it develops its acreage in the Big Horn
Basin.
Acquisition of the Assets of Genesis Gas and Oil, L.L.C.
In October 1997, the Company completed the acquisition of the assets of
Genesis Gas and Oil, L.L.C. ("Genesis"). The Genesis assets are located
primarily in the Piceance Basin of western Colorado and the Green River Basin of
Wyoming and are principally operated by the Company. The acquisition increased
the Company's acreage position in the Piceance Basin by approximately 32,000 net
developed and 48,000 net undeveloped acres. The Company's working interest
doubled from 23% to 46% in 238 producing wells and from 34% to 68% in 500
potential development locations. The purchase price for these assets was
approximately $35.5 million.
Acquisition of KN Production Company
The Company and KN Energy, Inc. ("KNE") closed certain transactions on
January 31, 1996 which resulted in (i) the Company's acquisition of all of the
issued and outstanding stock of KN Production Company ("KNPC"), a wholly owned
subsidiary of KNE, and (ii) Wildhorse being formed by the Company and KNE for
the purpose of providing gas gathering, processing, marketing, field and storage
services, (collectively the "KNPC Acquisition"). The price paid to KNE in
connection with the KNPC Acquisition was determined to be $36.25 million, of
which $25 million was paid in the form of 1.0 million shares of the Company's
$1.75 Convertible Preferred Stock, Series A (the "Preferred Stock") and the
remaining $11.25 million was paid in the form of 918,367 shares of the Company's
Common Stock, based on a price per share of $12.25. The KNPC Acquisition has
been recorded under the purchase method of accounting.
As a result of the KNPC Acquisition, the Company acquired interests in
624 gross producing wells in Colorado and Wyoming, of which the Company became
operator of 308. The properties acquired by the Company included approximately
243,000 net undeveloped acres in Colorado, Wyoming, Kansas and Nebraska and
approximately 64,000 net developed acres located in Colorado and Wyoming.
An integral part of the KNPC Acquisition was the formation of
Wildhorse, which is owned fifty-five percent
39
40
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
(55%) by KNE and forty-five percent (45%) by the Company. The business and
affairs of Wildhorse are managed by KNE under the direction of an operating team
consisting of two representatives appointed by the Company and two
representatives appointed by KNE. The Company dedicated a significant amount of
its Rocky Mountain gas reserves to Wildhorse and KNE contributed substantial gas
marketing contracts. The Company also acquired a natural gas storage facility in
western Colorado that was simultaneously transferred to Wildhorse.
The principal purpose of Wildhorse is to provide for the furnishing of
services related to natural gas, natural gas liquids and other natural gas
products, including gathering, processing and storage services.
Acquisition of Presidio Oil Company
In December 1996, the Company completed the acquisition of Presidio Oil
Company and its subsidiaries (collectively, "Presidio"), following the issuance
by the U.S. Bankruptcy Court, District of Delaware, on December 10, 1996, of an
Order confirming Presidio's reorganization under Chapter 11 of the U.S.
Bankruptcy Code. The purchase price was approximately $206.6 million consisting
of approximately $105 million in cash and 2.71 million shares of the Company's
Common Stock valued at $17.125 per share. Such amount does not include 2.64
million shares of the Company's Common Stock which were not issued due to the
Company's ownership of $56.15 million principal amount of Presidio Senior Gas
Indexed Notes (the "GINs"). The GINs were purchased in June 1995 for
approximately $51 million as a strategic part of the Company's efforts to
acquire Presidio Oil Company. The Presidio Acquisition has been accounted for
using the purchase method of accounting. The cash portion of the Presidio
Acquisition was funded by borrowings under the Company's credit facility with
its bank lender. The assets acquired consist primarily of proved oil and gas
properties and undeveloped acreage located in Wyoming, North Dakota, Oklahoma
and Louisiana. The Wyoming properties are concentrated in the Green River and
Powder River Basins of Wyoming.
Pro Forma Information
The following table presents the unaudited pro forma revenues, net
income and net income per share of the Company for the years ended December 31,
1997 and 1996 assuming that the Sauer, Genesis, KNPC, and Presidio Acquisitions
occurred on January 1, 1996.
Years ended December 31,
-----------------------------
1997 1996
------------ ------------
(in thousands, except for per share amounts)
Revenues $ 133,557 $ 112,826
============ ============
Net income $ 9,560 $ 9,154
============ ============
Net income attributable to common
stock $ 7,810 $ 7,482
============ ============
Net income per common share
Basic $ .31 $ .30
============ ============
Diluted $ .30 $ .29
============ ============
40
41
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
Sale of North Dakota Properties
In May 1997, the Company sold the majority of its properties located in
North Dakota for $11.0 million. The properties had a net book value of $11.0
million and, accordingly, no gain was recorded on the sale. Proceeds from the
sale of these properties were used to repay a portion of the Company's
outstanding indebtedness under its credit facility.
(4) DEBT
In April 1998, the Company repaid and cancelled its $125 million
revolving credit facility and entered into a new $75 million credit facility
(the New Credit Facility) that matures in April 2001. In October 1998, the
Company amended the New Credit Facility by increasing the total commitment to
$100 million. The New Credit Facility has a current borrowing base of $130
million. The amount of the borrowing base may be redetermined as of December
31 and June 30 of each calendar year at the sole discretion of the lender. A
redetermination as of December 31, 1998 has not yet been made.
Borrowings under the New Credit Facility are unsecured and bear
interest, at the election of the Company, at a rate equal to (i) the greater of
the agent bank's prime rate or the federal funds effective rate plus 0.50% or
(ii) the agent bank's Eurodollar rate plus a margin ranging from .75% to 1.25%.
Interest on amounts outstanding under the New Credit Facility is due on the last
day of each month in the case of loans bearing interest at the prime rate or
federal funds rate and, in the case of loans bearing interest at the Eurodollar
rate, interest payments are due on the last day of each applicable interest
period of one, two, three or six months, as selected by the Company at the time
of borrowing. At December 31, 1998, the outstanding balance was $55 million at
an average interest rate of 6.1% and $45 million was available for borrowing
under the New Credit Facility.
The New Credit Facility contains certain financial covenants among other
restrictions. Financial covenants of the New Credit Facility require the Company
to maintain a minimum consolidated tangible net worth of not less than $350
million. The Company is also required to maintain a ratio of (i) earnings before
interest expense, state and federal taxes and depreciation, depletion and
amortization expense to (ii) consolidated fixed charges, as defined in the New
Credit Facility, of not less than 2.5:1. Additionally, the Company is required
to maintain a ratio of consolidated debt to consolidated total capitalization of
less than 0.45:1. As a result of the non-cash charge of $51.3 million for the
impairment of gas and oil properties recorded in 1998, the Company was not in
compliance with the consolidated tangible net worth covenant at December 31,
1998. On March 15, 1999, the Company obtained a waiver of the net worth covenant
as of December 31, 1998 and amended the New Credit Facility to reduce the
minimum consolidated tangible net worth covenant to $300 million.
Standby letters of credit of approximately $2,188,000 have been issued
under two agreements. One agreement expires in April 1999 and the related letter
of credit being maintained is security for performance on a long term contract
entered into by Presidio. The second letter of credit is held as security by a
surety company for two oil and gas performance bonds issued to agencies of the
U.S. Government. The bonds will remain in place until released by the government
agencies.
41
42
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
(5) TAXES
The Company has not paid Federal income taxes due to its net operating
loss carryforward, but is required to pay alternative minimum tax ("AMT"). This
tax can be partially offset by an AMT net operating loss carryforward. A U.S.
Federal statutory rate applied to the Company's income (loss) before income
taxes of 35% in 1998, 1997 and 1996 was used in the following reconciliation of
the Company's effective income tax benefit (provision):
Years ended December 31,
------------------------------------
1998 1997 1996
-------- -------- --------
(in thousands)
Federal income tax benefit (provision)
at statutory rate $ 24,976 $ (4,548) $ (3,946)
Revisions of previous tax estimates 2,130 1,111 --
Adjustment to valuation allowance 2,980 474 596
Other (597) (395) 583
-------- -------- --------
29,489 (3,358) (2,767)
AMT provisions (380) (403) (290)
State income and franchise taxes (1,231) (623) (281)
-------- -------- --------
Income tax expense benefit (provision) $ 27,878 $ (4,384) $ (3,338)
======== ======== ========
The significant components, which give rise to the Company's deferred
tax assets (liabilities), are as follows:
December 31,
----------------------
1998 1997
-------- --------
(in thousands)
Net operating loss carryforward $ 10,950 $ 17,072
Gas and oil acquisition, exploration and development
costs deducted for tax purposes under (over) book 6,254 (16,819)
Advances from gas purchasers 8,585 --
AMT Credit Carryforwards 4,119 3,717
Investment tax credit carryforward 857 857
Option plan compensation 1,559 1,559
Other 2,265 1,775
-------- --------
Net deferred tax asset 34,589 8,161
Valuation allowance (2,575) (5,555)
-------- --------
Recognized net deferred tax asset $ 32,014 $ 2,606
======== ========
Net deferred tax assets are comprised of the following (in thousands):
December 31,
---------------------
1998 1997
-------- --------
(in thousands)
Current $ 8,585 $ --
Long-term 23,429 2,606
-------- --------
$ 32,014 $ 2,606
======== ========
42
43
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
A valuation allowance of approximately $2.6 million and $5.6 million at
December 31, 1998 and 1997, respectively, has been provided against the
Company's net deferred tax assets based on management's estimate of the
recoverability of future tax benefits. The Company evaluated all appropriate
factors to determine the proper valuation allowance for carryforwards, including
any limitations concerning their use, the year the carryforward expires, the
levels of taxable income necessary for utilization and tax planning. In this
regard, full valuation allowances were provided for investment tax credit
carryforwards and option plan compensation. Based on its recent operating
results and its expected levels of future earnings, the Company believes it
will, more likely than not, generate sufficient taxable income to realize the
benefit attributable to the net operating loss carryforward and other deferred
tax assets for which valuation allowances were not provided.
At December 31, 1998, the Company had investment tax credit
carryforwards of approximately $.9 million and a net operating loss carryforward
of approximately $31.3 million. The Company has no current liability for Federal
income taxes because of these net operating loss and investment tax credit
carryforwards. Realization of the benefits of these carryforwards is dependent
upon the Company's ability to generate taxable earnings in future periods. In
addition, the availability of these carryforwards is subject to various
limitations. The net operating loss carryforwards expire as follows: $17.6
million in 2000, $7.8 million in 2001, $.7 million in 2002, $2.9 million in
2003, and $2.3 million in 2004. Additionally, the Company has approximately $6.0
million of statutory depletion carryforwards and $4.1 million of AMT credit
carryforwards that may be carried forward until utilized.
(6) ADVANCES FROM GAS PURCHASERS
In 1998, the Company received $24.3 million from purchasers as advance
payments for future natural gas deliveries of 35,000 MMBtu per day for a twelve
month period commencing January 1999. In connection with the advances, the
Company entered into gas price swap contracts with third parties under which the
Company became a fixed price payor for identical volumes at a weighted average
price of $2.02 per MMBtu. The net result of these transactions is that gas
delivered to the purchaser is reported as revenue at a rate that approximates
the prevailing spot price.
The advance payments have been classified as advances on the balance
sheet and will be reduced as gas is delivered to the purchasers under the terms
of the contracts. Gas volumes delivered to the purchaser are reported as revenue
at prices used to calculate the amount advanced, before imputed interest, minus
or plus amounts paid or received by the Company applicable to the price swap
agreements. Interest expense is recorded based on an average rate of 9.7% on the
advances.
(7) STOCKHOLDERS' EQUITY
Common Stock
The Company's Common Stock is $.10 par value per share. There are
40,000,000 authorized shares of Common Stock of which 29,259,989 shares and
29,210,354 shares were outstanding at December 31, 1998 and 1997, respectively.
In October 1997, the Company sold 5,035,800 shares of Common Stock in a
public offering. The net proceeds of such offering were approximately $121.0
million and were used to repay a majority of the Company's
43
44
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
outstanding long-term debt and to fund the acquisition of all of the assets of
Genesis Gas and Oil, L.L.C. (See Note 3).
Rights Plan
On March 1, 1991, the Board of Directors adopted a Rights Plan designed
to help assure that all stockholders receive fair and equal treatment in the
event of a hostile attempt to take over the Company, and to help guard against
abusive takeover tactics. The Board of Directors declared a dividend of one
preferred share purchase right (a "Right") for each outstanding share of Common
Stock. The dividend was distributed on March 15, 1991 to the shareholders of
record on that date. Each Right entitles the registered holder to purchase, for
the $20 per share exercise price, shares of Common Stock or other securities of
the Company (or, under certain circumstances, of the acquiring person) worth
twice the per share exercise price of the Right.
The Rights will be exercisable only if a person or group acquires 20% or
more of the Company's Common Stock or announces a tender offer which would
result in ownership by a person or group of 20% or more of the Common Stock. The
date on which the above occurs is to be known as the ("Distribution Date"). The
Rights will expire on March 15, 2001, unless extended or redeemed earlier by the
Company.
At the time the Rights dividend was declared, the Board of Directors
further authorized the issuance of one Right with respect to each share of the
Company's Common Stock that shall become outstanding between March 15, 1991 and
the earlier of the Distribution Date or the expiration or redemption of the
Rights. Until the Distribution Date occurs, the certificates representing shares
of the Company's Common Stock also evidence the Rights. Following the
Distribution Date, the Rights will be evidenced by separate certificates.
The provisions described above may tend to deter any potential
unsolicited tender offers or other efforts to obtain control of the Company that
are not approved by the Board of Directors and thereby deprive the stockholders
of opportunities to sell shares of the Company's Common Stock at prices higher
than the prevailing market price. On the other hand, these provisions will tend
to assure continuity of management and corporate policies and to induce any
person seeking control of the Company or a business combination with the Company
to negotiate on terms acceptable to the then elected Board of Directors.
Preferred Stock
In January 1996, in connection with the KNPC Acquisition, (see Note 3)
the Company issued 1,000,000 shares of its $1.75 Convertible Preferred Stock,
Series A (the "Preferred Stock"). There are 2,500,000 shares of Preferred Stock
authorized.
As the holder of the Preferred Stock, KNE is entitled to receive
cumulative dividends at the annual rate of $1.75 per share, payable in cash
quarterly on the fifteenth day of March, June, September and December in each
year. If full cumulative dividends on the Preferred Stock have not been declared
and paid or set apart for payment, the Company may not declare or pay or set
apart for payment any dividends or make any other distributions on, or make any
payment on account of the purchase, redemption or retirement of, the Company's
Common Stock, or any other stock of the Company ranking junior to the Preferred
Stock as to payment of dividends or distribution of assets on liquidation,
dissolution or winding up of the Company (other than, in the case of dividends
or distributions, dividends or distributions paid in shares of Common Stock or
such other junior ranking stock).
The Company has the option, at any time beginning on or after March 15,
2001, to redeem all or any part of the outstanding shares of Preferred Stock at
the redemption price of $25.00 per share, plus an amount equal to all
44
45
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
accrued and unpaid dividends on such shares of Preferred Stock to the date of
redemption.
Upon the occurrence of a change of control of the Company, KNE, as the
holder of the Preferred Stock, has the right to cause the Preferred Stock to be
redeemed by the Company, in whole or in part, at the redemption price of $25.50
per share, plus all accrued and unpaid dividends. Generally, for purposes of the
Preferred Stock, a change of control is any situation in which a majority of the
Board of Directors of the Company changes within a period of twelve months or a
new person or group of persons becomes in control of the Company, within the
meaning of rules of the Securities and Exchange Commission.
Each share of the Preferred Stock is convertible at the option of the
holder thereof, at any time and from time to time prior to the redemption of
such share, into fully paid and nonassessable shares of Common Stock of the
Company at the initial conversion rate of 1.666 shares of Common Stock for each
share of Preferred Stock, subject to customary adjustments.
The Preferred Stock is exchangeable, in whole or in part, at the option
of the Company on any dividend payment date at any time on or after March 15,
1999, and prior to March 15, 2001, for shares of Common Stock at the exchange
rate of 1.666 shares of Common Stock for each share of Preferred Stock; provided
that (i) on or prior to the date of exchange, the Company shall have declared
and paid or set apart for payment to the holders of Preferred Stock all
accumulated and unpaid dividends to the date of exchange, and (ii) the current
market price of the Common Stock is above $18.375 (the "Threshold Price"). The
exchange rate is subject to adjustment in the same manner and under the same
circumstances as the conversion rate is subject to adjustment, and the Threshold
Price is also subject to adjustment in the same manner and under the same
circumstances.
Upon the dissolution, liquidation or winding up of the Company, whether
voluntary or involuntary, the holders of the Preferred Stock are entitled to
receive out of the assets of the Company available for distribution to
stockholders, the amount of $25.00 per share plus an amount equal to all
dividends on such shares (whether or not earned or declared) accrued and unpaid
thereon to the date of final distribution, before any payment or distribution
may be made on the Common Stock or on any class of stock ranking junior to the
Preferred Stock with respect to distributions upon dissolution, liquidation or
winding up.
If at any time dividends payable on the Preferred Stock are in arrears
and unpaid in an amount equal to or exceeding the amount of dividends payable
thereon for four quarterly dividend periods, the total number of Directors on
the Company's Board of Directors will be limited to a maximum of nine and the
holders of the outstanding Preferred Stock will have the exclusive right, voting
separately as a class without regard to series, to designate a special class of
two Directors of the Company (the "Special Directors") at the next annual or
special meeting of stockholders of the Company irrespective of whether such
meeting otherwise would involve the election of directors, and the membership of
the Board of Directors of the Company shall be increased by the number of the
Special Directors so designated. Such right of the holders of Preferred Stock to
designate Special Directors continues until all dividends accumulated and
payable on the Preferred Stock have been paid in full, at which time such right
to designate Special Directors terminates, subject to re-vesting in the event of
a subsequent dividend payment arrearage.
In exercising the right to designate Special Directors or when otherwise
granted voting rights by operation of law, each share of Preferred Stock shall
be entitled to one vote, except as described below.
For so long as KNE owns 80% or more of the voting power of the
securities of the Company issued pursuant to the KNPC Acquisition, KNE has the
right to elect a special class of two Directors to the Board of Directors of the
Company, and for so long as KNE owns securities of the Company issued pursuant
to the KNPC Acquisition
45
46
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
possessing less than 80% of the voting power of the securities of the Company
issued pursuant to the KNPC Acquisition, but more than 30% of such voting power,
KNE has the right to elect a special class of one Director to the Board of
Directors of the Company.
The holders of the Preferred Stock are entitled to vote on all matters
upon which holders of the Company's Common Stock have the right to vote. In such
voting, each share of Preferred Stock is entitled to a number of votes per share
equivalent to the number of shares of Common Stock issuable upon conversion of
the Preferred Stock and shall vote together with the holders of the outstanding
shares of the Company's Common Stock as if a part of that
class.
(8) BENEFIT PLANS
1989 Plan
On September 28, 1990, shareholders approved the Company's 1989 Stock
Option Plan (the "1989 Plan"). The aggregate number of shares of Common Stock
that may be issued under the 1989 Plan is 2,000,000 shares.
The exercise price of the options granted to employees and directors
prior to 1991, which was originally set at $5.25 per share, was reduced
effective September 4, 1991 to $4.00 per share, the market value at that date.
The options expire ten years from the date of grant.
1993 Plan
In February 1993, the Board of Directors adopted the Company's 1993
Stock Option Plan (the "1993 Plan"). The 1993 Plan provides for issuance of
options to certain employees and directors to purchase shares of Common Stock.
In September 1998, the aggregate number of shares of Common Stock that may be
issued under the 1993 Plan was increased to 2,700,000 shares. The exercise
price, vesting and duration of the options may vary and will be determined at
the time of issuance.
46
47
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
A summary of the status of the plans described above, as of the dates
indicated, and the changes during the years then ended, is presented in the
table and narrative below:
December 31,
----------------------------------------------------------------------------
1998 1997 1996
---------------------- ---------------------- ----------------------
(shares in thousands)
Wtd. Wtd. Wtd.
Shares Avg. Shares Avg. Shares Avg.
Under Exer. Under Exer. Under Exer.
Option Price Option Price Option Price
-------- -------- -------- -------- -------- --------
Outstanding, beginning of year 2,173 $ 12.84 2,110 $ 11.06 1,525 $ 8.72
Granted 2,127 16.04 307 19.12 673 15.70
Exercised (50) 11.80 (244) 5.54 (88) 5.89
Cancellations (848) 19.43 -- -- -- --
-------- -------- --------
Outstanding, end of year 3,402 13.22 2,173 12.84 2,110 11.06
======== ======== ========
Exercisable, end of year 1,919 11.64 1,501 10.77 1,457 8.99
======== ======== ========
Available for grant, end of year 945 741 31
======== ======== ========
The weighted average fair value of options granted during the years
ended December 31, 1998, 1997, and 1996 was $9.01, $10.35, and $9.19,
respectively.
The following table summarizes information about stock options
outstanding at December 31, 1998:
Options Outstanding Options Exercisable
---------------------------------------------- ------------------------------
No. of Shs. Wtd. Avg. No. of Shs.
Range of Under Remaining Wtd. Avg. Under Wtd. Avg.
Exercise Outstanding Contractual Exercise Exercisable Exercise
Prices Options Life Price Options Price
- ------------------ ----- ---- ------- ------ -------
(shares in thousands)
$ 3.81 to 13.00 1,138 5.56 $ 8.69 988 $ 8.23
$13.32 to 15.25 650 6.30 15.02 579 14.99
$15.69 to 18.38 1,614 9.01 15.69 352 15.69
----- ------
3,402 7.34 $ 13.22 1,919 $ 11.64
===== =====
47
48
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
The Company accounts for its stock-based compensation using the
intrinsic value method prescribed by APB Opinion No. 25 and related
interpretations, under which no compensation cost has been recognized for the
stock option plans. Alternatively, if compensation costs for these plans had
been determined in accordance with SFAS No. 123, the Company's net income and
net income per share would approximate the following pro forma amounts:
Years ended December 31,
-----------------------------------------
1998 1997 1996
---------- ---------- ----------
(in thousands, except per share amounts)
Net Income (loss)
As Reported $ (45,233) $ 6,860 $ 6,263
Pro Forma (48,645) 4,708 4,729
Basic Net Income (loss) per Common Share:
As Reported $ (1.55) $ 0.27 $ 0.30
Pro Forma $ (1.66) 0.19 0.22
Diluted Net Income (loss) per Common Share:
As Reported $ (1.55) $ 0.26 $ 0.28
Pro Forma $ (1.66) 0.18 0.21
The fair value of each option is estimated as of the date of grant using
the Black-Scholes option-pricing model with the following weighted-average
assumptions used for grants in 1998, 1997, and 1996 respectively: (i) risk-free
interest rates of 5.54, 6.20 and 6.35 percent; (ii) expected lives of 7.3 years,
(iii) expected volatility of 44.3, 40.9, and 45.4 percent , and (iv) no dividend
yields. The pro forma amounts shown above may not be representative of future
results because the SFAS No. 123 method of accounting has not been applied to
options granted prior to January 1, 1995.
Profit Sharing, ESOP and KSOP Plans
Effective April 1, 1985, the Company adopted a profit sharing plan (the
"Profit Sharing Plan") for the benefit of all employees. Under the Profit
Sharing Plan, the Company could contribute to a trust either stock or cash in
such amounts as the Company deemed advisable.
Effective April 1, 1986, the Company adopted an employee stock ownership
plan (the "ESOP") for the benefit of all employees. Under the ESOP, the Company
could contribute cash or the Company's Common Stock to a trust in such amounts
as the Company deemed advisable.
Effective April 1, 1990, the Profit Sharing Plan was amended to provide
for voluntary employee contributions under Section 401(k) of the Internal
Revenue Code of 1986, as amended. The Profit Sharing Plan was further amended to
provide employees with the ability to give direct investment instructions to the
Profit Sharing Trustee for amounts held for their benefit.
Effective January 1, 1996 the Company adopted the KSOP which is a merger
of the ESOP and the Profit Sharing Plan which contains 401(k) profit sharing
plan and employer stock ownership plan provisions for the benefit of those
persons who qualify as participants. The Company has, at its discretion, a
policy to match employee contributions to the plan. As of December 31, 1998 the
Company's policy was to match two-thirds of the employee contribution up to a
total match of four percent of the employee's salary. The match for the years
ended December 31, 1998 and 1997 was approximately $329,000 and $266,000
respectively. The Company contributed an additional $100,000 to the KSOP for
1997 and 1996 respectively.
48
49
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
(9) FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair
value of financial instruments. The carrying values of trade receivables and
trade payables approximated market value. The carrying amounts of cash and cash
equivalents approximated fair value due to the short maturity of these
instruments. The carrying value of debt approximated fair value because the
interest rate is variable and is reflective of current market conditions. The
letters of credit reflect fair values as a condition of the underlying purpose
and are subject to fees competitively determined in the market place.
As discussed in Note 6, as of December 31, 1998, in connection with
advance payments for future natural gas deliveries, the Company had three gas
price swap contracts outstanding whereby the Company became a fixed price payor
for a total of 35,000 Mmbtu per day at a weighted average price of $2.02. At
December 31, 1998, the estimated fair value of the open gas price swap contracts
was an unrealized loss of $1.2 million. There was no carrying value for the
contracts at December 31, 1998.
(10) RELATED PARTIES AND SIGNIFICANT CUSTOMERS
Related Parties
Certain of the Company's officers and directors participate (either
individually or indirectly through various entities) with the Company and other
unrelated investors in the drilling, development and operation of gas and oil
properties. Related party transactions are non-interest bearing and are settled
in the normal course of business with terms which, in management's opinion, are
similar to those with other joint owners.
The Company has engaged from time to time two law firms, one of whose
partner serves as a director and one of whose partner served as an officer
through May 1997. The amounts paid to each of these firms for the years ended
December 31, 1998, 1997 and 1996 were approximately $100,000, and $35,000;
$189,000 and $110,000; and $56,000 and $268,000, respectively. The Company also
paid approximately $35,000, $32,000 and $74,000 during the years ended December
31, 1998, 1997 and 1996, respectively, to a consulting firm that has a partner
who serves as a director of the Company.
The Company participates in exploration activity with a partnership, one
of whose partner is a director of the Company. During the years ended December
31, 1998, 1997, and 1996 the Company billed $508,000, $960,000 and $239,000,
respectively to such partnership for their share of certain leasehold and
drilling costs.
In addition, certain officers and directors of the Company are directors
of a former subsidiary. The Company and the former subsidiary make available to
each other certain personnel, office services and records with each
49
50
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
party being reimbursed for costs and expenses incurred in connection therewith.
During the years ended December 31, 1998, 1997 and 1996, the Company charged the
former subsidiary approximately $86,000, $80,000 and $75,000, respectively, for
such services. The former subsidiary performs drilling services on certain wells
operated by the Company and charged approximately $1,643,000, $11,000 and
$42,000 for such services during the years ended December 31, 1998, 1997 and
1996, respectively.
In management's opinion, the above described transactions and services
were provided on the same terms as could be obtained from non-related sources.
Significant Customers
Gas and oil sales to Conoco, Inc. accounted for 24% and 28% of gas and
oil sales and marketing, gathering and processing revenues for the years ended
December 31, 1998 and 1997, respectively. For the year ended 1996, gas and oil
sales to three purchasers, Coastal Oil and Gas, Conoco, Inc. and KN Gas
Marketing, Inc. accounted for 15%, 14% and 13%, respectively. Because there are
numerous other parties available to purchase the Company's production, the
Company believes the loss of these purchasers would not materially affect its
ability to sell natural gas or crude oil.
Concentration of Credit Risk
The Company's revenues are derived principally from uncollateralized
sales to customers in the oil and gas industry. The concentration of credit risk
in a single industry affects the Company's overall exposure to credit risk
because customers may be similarly affected by changes in economic and other
conditions. The Company has not experienced significant credit losses on such
receivables.
(11) SEGMENT INFORMATION
The Company adopted SFAS No. 131, "Disclosures About Segments of an
Enterprise and Related Information", in 1998 which changes the way the Company
reports information about its operating segments. The information for 1997 and
1996 has been restated from the prior year's presentation in order to conform
with 1998 presentation.
The Company operates in three reportable segments: (i) gas and oil
exploration and development, (ii) marketing, gathering and processing and (iii)
drilling. The long-term financial performance of each of the reportable segments
is affected by similar economic conditions.
The Company's gas and oil exploration and development segment operates
primarily in the Wind River and Green River Basins of Wyoming, the Piceance
Basin of Colorado, the Val Verde of west Texas, the Permian Basin of west Texas
and southwestern New Mexico, and east Texas. The marketing, gathering and
processing activities of the Company are conducted through Wildhorse, primarily
in the Rocky Mountain region. The drilling segment operates under the name of
Sauer Drilling Company and serves the drilling needs of operators in the central
Rocky Mountain region in addition to drilling for the Company.
The accounting policies of the segments are the same as those described
in Note 2 of Notes to Consolidated Financial Statements. The Company evaluates
performance based on profit or loss from operations before income taxes,
accounting changes, nonrecurring items and interest income and expense.
The Company accounts for intersegment sales transfers as if the sales or
transfers were to third parties, that is, at current prices.
50
51
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
The following tables present information related to the Companies' reportable
segments.
December 31, 1998
-----------------------------------------------------------------
Gas & Oil Marketing,
Exploration Gathering
& & Total
Development Processing Drilling Segments
------------ ------------ ------------ ------------
Revenues from external purchasers $ 63,262 $ 55,037 $ 4,558 $ 122,857
Intersegment revenues 15,406 -- 5,117 20,523
Depreciation, depletion and amortization 42,399 1,846 1,008 45,253
Impairment of gas and oil properties 51,344 -- -- 51,344
Segment profit (loss) (62,989) (3,808) 283 (66,514)
Assets 360,347 74,785 9,094 444,226
Capital and exploration expenditures 75,447 8,630 9,197 93,274
December 31, 1997
-----------------------------------------------------------------
Gas & Oil Marketing,
Exploration Gathering
& & Total
Development Processing Drilling Segments
------------ ------------ ------------ ------------
Revenues from external purchasers $ 76,172 $ 41,853 -- $ 118,025
Intersegment revenues 15,182 -- -- 15,182
Depreciation, depletion and amortization 35,229 1,001 -- 36,230
Segment profit 15,623 3,291 -- 18,914
Assets 394,762 57,628 -- 452,390
Capital and exploration expenditures 94,902 17,213 -- 112,115
December 31, 1996
-----------------------------------------------------------------
Gas & Oil Marketing,
Exploration Gathering
& & Total
Development Processing Drilling Segments
------------ ------------ ------------ ------------
Revenues from external purchasers $ 31,117 $ 29,476 -- $ 60,593
Intersegment revenues 9,676 -- -- 9,676
Depreciation, depletion and amortization 13,762 1,378 -- 15,140
Segment profit 7,806 3,856 -- 11,662
Assets 383,697 24,923 -- 408,620
Capital and exploration expenditures 258,623 24,550 -- 283,173
51
52
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
The following tables reconcile segment information to consolidated
totals:
December 31,
------------------------------------------
1998 1997 1996
---------- ---------- ----------
Revenues
Revenue from external purchasers $ 122,857 $ 118,025 $ 60,593
Intersegment revenues 20,523 15,182 9,676
Intercompany eliminations (12,050) (6,832) (4,354)
---------- ---------- ----------
Total consolidated revenues $ 131,330 $ 126,375 $ 65,915
========== ========== ==========
Profit or (loss)
Total reportable segment profit/(loss) $ (66,514) $ 18,914 $ 11,662
Interest expense (4,301) (5,920) (389)
Eliminations and other (546) -- --
---------- ---------- ----------
Income (loss) before income taxes $ (71,361) $ 12,994 $ 11,273
========== ========== ==========
Depreciation, depletion and amortization
Total reportable segment depreciation, $ 45,253 $ 36,230 $ 15,140
depletion and amortization
Eliminations and other (678) -- --
---------- ---------- ----------
$ 44,575 $ 36,230 $ 15,140
========== ========== ==========
Assets
Total reportable segment assets $ 444,226 $ 452,390 $ 408,620
Eliminations and other (2,344) (1,464) (2,246)
---------- ---------- ----------
$ 441,882 $ 450,926 $ 406,374
========== ========== ==========
(12) COMMITMENTS AND CONTINGENCIES
The Company's operations are subject to numerous Federal and state
government regulations that may give rise to claims against the Company. In
addition, the Company is a defendant in various lawsuits generally incidental to
its business. The Company does not believe that the ultimate resolution of such
litigation will have a material adverse effect on the Company's financial
position, results of operations or cash flows.
Lease Commitments
At December 31, 1998, the Company had long-term leases covering certain
of its facilities and equipment.
52
53
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
The minimum rental commitments under non-cancelable operating leases with lease
terms in excess of one year are as follows:
Years ending Commitment
December 31, Amount
----------- --------------
(in thousands)
1999 $ 1,215
2000 1,175
2001 1,182
2002 1,164
2003 1,267
Thereafter 103
-------
$ 6,106
=======
Total rental expense incurred for the years ended December 31, 1998, 1997
and 1996 was approximately $1,043,000, $741,000 and $394,000, respectively, all
of which represented minimum rentals under non-cancelable operating leases.
Firm Transportation Commitments
As of December 31, 1998, Wildhorse had entered into several contracts for
firm transportation on interstate pipelines. On January 23, 1998, the owner of
one interstate pipeline filed for an interim rate increase on a regulated
pipeline effective August 1, 1998. The requested increase from approximately
$.45 to $.76 is subject to final approval by F.E.R.C., but has been accrued by
the Company.
Based upon current rates and the Company's forty-five percent (45%)
ownership in Wildhorse, including its share of such rate increase of
approximately $6,948,000 over the life of the contract, the Company's obligation
for such firm transportation on that pipeline and others for the next five years
and thereafter is as follows:
Years ending Commitment
December 31, Amount
----------- --------------
(in thousands)
1999 $ 5,356
2000 5,583
2001 5,383
2002 4,594
2003 1,761
Thereafter 2,610
---------
$ 25,287
=========
53
54
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
Environmental Matters
A wholly owned subsidiary of the Company is a party to an environmental
cleanup proceeding. The subsidiary's share of the estimated cleanup costs was
accrued in the consolidated financial statements at December 31, 1998. Based on
the amount of remediation costs estimated for this site and the Company's de
minimis contribution, if any, the Company believes that the outcome of this
proceeding will not have a material adverse
effect on its financial position or results of operations.
(13) QUARTERLY FINANCIAL DATA (UNAUDITED)
First Second Third Fourth
Quarter Quarter Quarter Quarter Total
--------- --------- --------- --------- ---------
(in thousands, except per share amounts)
Year ended
December 31, 1998
- -------------------
Revenues $ 31,960 $ 32,644 $ 31,395 $ 35,331 $ 131,330
Gross profit (1) 14,631 15,952 12,425 12,569 $ 55,577
Net loss attributable
to common stock (2,032) (2,201) (5,222) (35,778) $ (45,233)
Net loss per
common share (2)
Basic (.07) (.08) (.18) (1.22) $ (1.55)
Diluted (.07) (.08) (.18) (1.22) $ (1.55)
Year ended
December 31, 1997
- -------------------
Revenues $ 35,874 $ 26,362 $ 26,966 $ 37,173 $ 126,375
Gross profit (1) 23,351 15,211 14,742 20,406 $ 73,710
Net income (loss)
attributable to common
stock 6,015 252 (338) 931 $ 6,860
Net income (loss) per
common share (2)
Basic .25 .01 (.01) .03 $ .27
Diluted .24 .01 (.01) .03 $ .26
(1) Gross Profit is computed as the excess of gas and oil and marketing,
gathering and processing revenues over operating expenses. Operating
expenses are those associated directly with gas and oil and marketing,
gathering and processing revenues and include lease operations, gas and
oil related taxes cost of gas sold and other expenses.
(2) The sum of the individual quarterly net income (loss) per share may not
agree with year-to-date net income (loss) per share as each period's
computation is based on the weighted average number of common shares
outstanding during the period.
54
55
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
(14) SUPPLEMENTAL INFORMATION RELATED TO GAS AND OIL ACTIVITIES (UNAUDITED)
The following tables set forth certain historical costs and operating
information related to the Company's gas and oil producing activities:
Capitalized Costs and Costs Incurred
December 31,
-----------------------------------------
1998 1997 1996
---------- ---------- ----------
(in thousands)
Capitalized costs
Proved gas and oil properties $ 344,766 $ 456,093 $ 392,192
Unproved gas and oil properties 42,570 44,468 44,687
---------- ---------- ---------
Total gas and oil properties 387,336 500,561 436,879
Less: Accumulated depreciation,
depletion and amortization (78,161) (151,544) (118,635)
---------- ---------- ---------
Net capitalized costs $ 309,175 $ 349,017 $ 318,244
========== ========== =========
Years ended December 31,
-----------------------------------------
1998 1997 1996
---------- ---------- ----------
(in thousands)
Costs incurred
Proved property
acquisition costs $ -- $ 35,540 $ 194,869
Unproved property
acquisition costs 3,283 6,128 42,877
Exploration costs 22,844 16,036 6,040
Development costs 49,262 33,731 13,177
---------- ---------- ---------
Total $ 75,389 $ 91,435 $ 256,963
========== ========== =========
Gas and Oil Reserve Information (Unaudited)
The following summarizes the policies used by the Company in preparing
the accompanying gas and oil reserve disclosures, Standardized Measure of
Discounted Future Net Cash Flows Relating to Proved Gas and Oil Reserves and
reconciliation of such standardized measure between years.
Estimates of proved and proved developed reserves at December 31, 1998,
1997 and 1996 were principally prepared by independent petroleum consultants.
Proved reserves are estimated quantities of natural gas and crude oil which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves that can be
recovered through existing wells with existing equipment and operating methods.
All of the Company's gas and oil reserves are located in the United States.
55
56
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
The standardized measure of discounted future net cash flows from
production of proved reserves was developed as follows:
1. Estimates are made of quantities of proved reserves and the future
periods during which they are expected to be produced based on year end economic
conditions.
2. The estimated future cash flows from proved reserves were determined
based on year-end prices, except in those instances where fixed and determinable
price escalations are included in existing contracts.
3. The future cash flows are reduced by estimated production costs and
costs to develop and produce the proved reserves, all based on year end economic
conditions and by the estimated effect of future income taxes based on the
then-enacted tax law, the Company's tax basis in its proved gas and oil
properties and the effect of net operating loss, investment tax credit and other
carryforwards.
The standardized measure of discounted future net cash flows does not
purport to present, nor should it be interpreted to present, the fair value of
the Company's gas and oil reserves. An estimate of fair value would also take
into account, among other things, the recovery of reserves not presently
classified as proved, anticipated future changes in prices and costs and a
discount factor more representative of the time value of money and the risks
inherent in reserve estimates.
56
57
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
Quantities of Gas and Oil Reserves (Unaudited)
The following table presents estimates of the Company's net proved and
proved developed natural gas and oil reserves (including natural gas liquids).
Reserve Quantities
----------------------
Gas Oil
Proved reserves: (Mmcf) (Mbls)
-------- -------
Estimated reserves at December 31, 1995 163,303 4,068
Revisions of previous estimates 10,249 (471)
Purchase of minerals in place 174,185 6,278
Extensions and discoveries 28,192 2,976
Production (16,762) (545)
-------- -------
Estimated reserves at December 31, 1996 359,167 12,306
Revisions of previous estimates (41,299) (2,763)
Purchase of minerals in place 23,341 268
Extensions and discoveries 38,487 189
Sales of minerals in place (750) (1,614)
Production (31,842) (1,159)
-------- -------
Estimated reserves at December 31, 1997 347,104 7,227
Revisions of previous estimates (7,021) (1,211)
Extensions and discoveries 67,921 711
Sales of minerals in place (95) (18)
Production (35,887) (1,027)
-------- -------
Estimated reserves at December 31, 1998 372,022 5,682
======== =======
Proved developed reserves:
December 31, 1995 109,267 2,862
December 31, 1996 257,241 8,994
December 31, 1997 258,756 5,749
December 31, 1998 263,747 4,029
57
58
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Gas
and Oil Reserves (Unaudited)
December 31,
------------------------------------------------
1998 1997 1996
------------ ------------ ------------
(in thousands)
Future cash flows $ 764,974 $ 805,645 $ 1,523,845
Future production costs (217,632) (225,488) (380,453)
Future development costs (74,371) (50,839) (62,124)
------------ ------------ ------------
Future net cash flows before tax 472,971 529,318 1,081,268
Future income taxes (71,960) (77,277) (265,260)
------------ ------------ ------------
Future net cash flows after tax 401,011 452,041 816,008
Annual discount at 10% (179,294) (186,867) (349,795)
------------ ------------ ------------
Standardized measure of
discounted future net cash flows $ 221,717 $ 265,174 $ 466,213
============ ============ ============
Discounted future net cash flows
before income taxes $ 254,020 $ 300,814 $ 608,746
============ ============ ============
Natural gas prices have declined and oil prices have increased since
December 31, 1998. Accordingly, the discounted future net cash flows shown above
could be different if the standardized measure were calculated using prices in
effect at the end of the first quarter.
58
59
TOM BROWN, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
(Continued)
Changes in Standardized Measure of Discounted Future Net Cash Flows
(Unaudited)
Years ended December 31,
------------------------------------------
1998 1997 1996
---------- ---------- ----------
(in thousands)
Gas and oil sales, net
of production costs $ (56,032) $ (68,446) $ (30,955)
Net changes in
anticipated prices
and production cost (36,581) (267,369) 129,492
Extensions and
discoveries, less
related costs 33,651 28,816 81,675
Changes in estimated
future development
costs (2,652) 21,347 (1,985)
Previously estimated
development costs
incurred 8,690 315 428
Net change in income
taxes 3,336 106,893 (131,293)
Purchase of minerals
in place -- 16,059 288,643
Sales of minerals
in place (151) (11,534) (37)
Accretion of discount 30,081 60,875 11,458
Revision of quantity
estimates (10,716) (49,263) 16,993
Changes in production
rates and other (13,083) (38,732) (1,553)
---------- ---------- ----------
Change in
Standardized Measure $ (43,457) $ (201,039) $ 362,866
========== ========== ==========
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60
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
Certain information regarding Directors of the Company will be included
in the Company's definitive proxy statement to be filed with the Securities and
Exchange Commission not later than 120 days after the end of the Company's
fiscal year covered by this Form 10-K and such information is incorporated by
reference to the Company's definitive proxy statement. Information concerning
the Executive Officers of the Company appears under Item I of this Annual Report
on Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
Certain information regarding compensation of executive officers of the
Company will be included in the Company's definitive proxy statement to be filed
with the Securities and Exchange Commission not later than 120 days after the
end of the Company's fiscal year covered by this Form 10-K and such information
is incorporated by reference to the Company's definitive proxy statement.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Certain information regarding security ownership of certain beneficial
owners and management will be included in the Company's definitive proxy
statement to be filed with the Securities and Exchange Commission not later than
120 days after the end of the Company's fiscal year covered by this Form 10-K
and such information is incorporated by reference to the Company's definitive
proxy statement.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Certain information regarding transactions with management and other
related parties will be included in the Company's definitive proxy statement to
be filed with the Securities and Exchange Commission not later than 120 days
after the end of the Company's fiscal year covered by this Form 10-K and such
information is incorporated by reference to the Company's definitive proxy
statement.
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61
PART IV
ITEM 14. EXHIBITS, CONSOLIDATED FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
(1) See Index to Consolidated Financial Statements under Item 8 of this
Annual Report on Form 10-K.
(2) None
(3) Exhibits:
(2.1) Exchange Agreement dated August 5, 1996 by and among Presidio
Oil Company, Presidio Exploration, Inc., Presidio West
Virginia, Inc., Palisade Oil, Inc. and the Registrant
(Incorporated by reference to Exhibit No. 2.1 in the
Registrant's Quarterly Report on Form 10-Q for the six months
ended June 30, 1996).
(2.2) First Amendment to Exchange Agreement dated August 20, 1996 by
and among Presidio Oil Company, Presidio Exploration, Inc.,
Presidio West Virginia, Inc., Palisade Oil, Inc. and the
Registrant (Incorporated by reference to Exhibit No. 2.2 in
the Registrant's Form 8-K Report dated December 23, 1996 and
filed with the Securities and Exchange Commission on January
6, 1997).
(2.3) Second Amendment to Exchange Agreement dated September 5, 1996
by and among Presidio Oil Company, Presidio Exploration, Inc.,
Presidio West Virginia, Inc., Palisade Oil, Inc. and the
Registrant (Incorporated by reference to Exhibit No. 2.3 in
the Registrant's Form 8-K Report dated December 23, 1996 and
filed with the Securities and Exchange Commission on January
6, 1997).
(2.4) Third Amendment to Exchange Agreement dated November 20, 1996
by and among Presidio Oil Company, Presidio Exploration, Inc.,
Presidio West Virginia, Inc., Palisade Oil, Inc. and the
Registrant (Incorporated by reference to Exhibit No. 2.4 in
the Registrant's Form 8-K Report dated December 23, 1996 and
filed with the Securities and Exchange Commission on January
6, 1997).
(3.1) Certificate of Incorporation, as amended, of the Registrant
(Incorporated by reference to Exhibit No. 4 in the
Registrant's Form 10-Q Report for the quarterly period ended
June 30, 1996 and filed with the Securities and Exchange
Commission on August 14, 1996).
(3.2) Bylaws of the Registrant (Incorporated by reference to Exhibit
No. 3.2 in the Registrant's Form 8-B Registration Statement
dated July 15, 1987 and filed with the Securities and Exchange
Commission on July 17, 1987).
61
62
(4.1) Rights Agreement dated as of March 5, 1991 between the
Registrant and The First National Bank of Boston, successor in
interest to American Stock Transfer & Trust Company
(Incorporated by reference to Exhibit No. 4(a) in the
Registrant's Form 8-K Report dated March 12, 1991 and filed
with the Securities and Exchange Commission on March 15,
1991).
(10.1) Wind River Gathering Company Joint Venture Agreement between
Retex Gathering Company, Inc. and KN Gas Gathering, Inc. dated
March 18, 1991 (Incorporated by reference to Exhibit No. 10.5
in the Registrant's Form S-1 Registration Statement dated May
3, 1993 and filed with the Securities and Exchange Commission
on May 4, 1993).
(10.2) Agreement and Plan of Reorganization, dated January 31, 1996,
by and among the Registrant, TBI Acquisition, Inc., KN
Production Company and KN Energy, Inc. (Incorporated by
reference to Exhibit No. 10.1 in the Registrant?s Form 8-K
Report dated January 31, 1996 and filed with the Securities
and Exchange Commission on February 15, 1996).
(10.3) Limited Liability Company Agreement, dated January 31, 1996,
of Wildhorse Energy Partners, LLC, between the Registrant and
KN Energy, Inc. (Incorporated by reference to Exhibit No. 10.2
in the Registrant's Form 8-K Report dated January 31, 1996 and
filed with the Securities and Exchange Commission on February
15, 1996).
(10.4) Registration Rights Agreement, dated January 31, 1996, between
the Registrant and KN Energy, Inc. (Incorporated by reference
to Exhibit No. 10.4 in the Registrant's Form 8-K Report dated
January 31, 1996 and filed with the Securities and Exchange
Commission on February 15, 1996).
(10.5) Credit Agreement, dated as of April 17, 1998, among the
Registrant, The Chase Manhattan Bank and the other lenders
parties thereto. (Incorporated by reference to Exhibit 10.1 in
the Registrant's Form 10-Q Report dated March 31, 1998 and
filed with the Securities and Exchange Commission on May 12,
1998.
(10.6) First Amendment, dated October 19, 1998, to the Credit
Agreement, dated April 17, 1998. (Incorporated by reference to
Exhibit 10.1 in the Registrant's Form 10-Q Report dated
September 30, 1998 and filed with the Securities and Exchange
Commission on November 12, 1998).
(10.7)* Second Amendment and Waiver, dated March 15, 1999, to the
Credit Agreement, dated April 17, 1998.
62
63
(10.8) Purchase and Sale Agreement between Genesis Gas and Oil,
L.L.C. and TBI Production Company, dated October 1, 1997.
(Incorporated by reference to Exhibit 10.6 in the Registrants'
Form 10-K Report dated December 31, 1997 and filed with the
Securities and Exchange Commission on March 26, 1998).
Executive Compensation Plans and Arrangements (Exhibits 10.9
through 10.15):
(10.9) 1989 Stock Option Plan (Incorporated by reference to Exhibit
No. 10.17 in the Registrant's Form S-1 Registration Statement
dated February 14, 1990 and filed with the Securities and
Exchange Commission on February 13, 1990).
(10.10) Tom Brown, Inc. KSOP Plan (Incorporated by reference to
Exhibit 10.19 in the Registrants' Form 10-K Report dated March
24, 1997 and filed with the Securities and Exchange Commission
on March 27, 1997).
(10.11) Second Amended and Restated Employment Agreement dated January
1, 1997 between the Registrant and Donald L. Evans
(Incorporated by reference to Exhibit 10.15 in the
Registrants' Form 10-K Report dated March 24, 1997 and filed
with the Securities and Exchange Commission on March 27,
1997).
(10.12) First Amendment to Employment Agreement dated as of July 1,
1998 between the Registrant and Donald L. Evans. (Incorporated
by reference to Exhibit 10.3 in the Registrant's Form 10-Q
Report dated June 30, 1998 and filed with the Securities and
Exchange Commission on August 10, 1998).
(10.13) 1993 Stock Option Plan (Incorporated by reference to Exhibit
10.25 in the Registrant's Form 10-K Report dated March 26,
1993 and filed with the Securities and Exchange Commission on
March 31, 1993).
(10.14) Severance Agreement dated as of July 1, 1998 together with a
schedule identifying officers of the Registrant who are
parties thereto and the multiple of earnings payable to each
officer upon termination resulting from certain change in
control events. (Incorporated by reference to Exhibit 10.1 in
the Registrant's Form 10-Q Report dated June 30, 1998 and
filed with the Securities and Exchange Commission on August
10, 1998).
(10.15) The Registrant's Severance Plan dated as of July 1, 1998.
(Incorporated by reference to Exhibit 10.2 in the Registrant's
Form 10-Q Report dated June 30, 1998 and filed with the
Securities and Exchange Commission on August 10, 1998).
(21.1)* Subsidiaries of the Registrant.
(23.1)* Consent of Arthur Andersen LLP.
(23.2)* Consent of Williamson Petroleum Consultants, Inc.
(23.3)* Consent of Ryder Scott Company.
(27.1)* Financial Data Schedule
- ----------
* Filed herewith
63
64
(4) Reports on Form 8-K:
None
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65
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.
TOM BROWN, INC.
By /s/ Donald L. Evans Date: March 16, 1999
----------------------------------
Donald L. Evans
Chairman of the Board of Directors
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.
SIGNATURE TITLE DATE
- --------- ----- ----
/s/ Donald L. Evans Chairman of the Board and March 16, 1999
- --------------------------------- Chief Executive Officer
Donald L. Evans
/s/ William R. Granberry President and Director March 16, 1999
- ---------------------------------
William R. Granberry
/s/ Damon Button Executive Vice President and March 16, 1999
- --------------------------------- Chief Financial Officer
Damon Button
/s/ R. Kim Harris Controller March 16, 1999
- ---------------------------------
R. Kim Harris
/s/ Thomas C. Brown Director March 16, 1999
- ---------------------------------
Thomas C. Brown
/s/ Edward W. LeBaron, Jr. Director March 16, 1999
- ---------------------------------
Edward W. LeBaron, Jr.
/s/ Henry Groppe Director March 16, 1999
- ---------------------------------
Henry Groppe
/s/ Robert H. Whilden, Jr. Director March 16, 1999
- ---------------------------------
Robert H. Whilden, Jr.
/s/ James B. Wallace Director March 16, 1999
- ---------------------------------
James B. Wallace
/s/ David M. Carmichael Director March 16, 1999
- ---------------------------------
David M. Carmichael
/s/ Clyde McKenzie Director March 16, 1999
- ---------------------------------
Clyde McKenzie
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66
TOM BROWN, INC.
EXHIBITS
TO
ANNUAL REPORT ON FORM 10-K
FOR THE PERIOD ENDED
December 31, 1998
66
67
INDEX TO EXHIBITS
Exhibit
No. Exhibit
- ------- -------
10.7 Second Amendment and Waiver, dated March 15, 1999,
to the Credit Agreement, dated April 17, 1998.
21.1 Subsidiaries of the Registrant.
23.1 Consent of Arthur Andersen LLP.
23.2 Consent of Williamson Petroleum Consultants, Inc.
23.3 Consent of Ryder Scott Company.
27.1 Financial Data Schedule.
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