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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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(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, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 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 incorporation (I.R.S. Employer Identification No.)
or organization)
555 SEVENTEENTH STREET
SUITE 1850
DENVER, COLORADO 80202
(Address of principal executive offices) (Zip Code)
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303-260-5000
(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. Yes [ ] No [ ]
The aggregate market value of the Registrant's Common Stock held by
non-affiliates (based upon the last sale price of $16.125 per share as quoted on
the NASDAQ National Market System) on March 17, 2000 was approximately
$569,604,725.
As of March 17, 2000, there were 35,324,324 shares of Common Stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's definitive proxy statement for the 2000 Annual
Meeting of Stockholders to be held on May 18, 2000 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.................................................. 9
Item 3. Legal Proceedings........................................... 12
Item 4. Submission of Matters to a Vote of Security Holders......... 12
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters....................................... 13
Item 6. Selected Financial Data..................................... 14
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 15
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk...................................................... 20
Item 8. Financial Statements and Supplementary Data................. 22
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 49
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 49
Item 11. Executive Compensation...................................... 49
Item 12. Security Ownership of Certain Beneficial Owners and
Management................................................ 49
Item 13. Certain Relationships and Related Transactions.............. 49
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K....................................................... 50
Signatures.................................................. 53
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PART I
ITEM 1. BUSINESS
GENERAL
Tom Brown, Inc. (the "Company") was organized in 1955 as a privately-owned
drilling company known as Scarber-Brown Drilling Company and in 1959 as Tom
Brown Drilling Company, Inc. In 1968, the Company merged into Gold Metals
Consolidated Mining Company, a publicly-traded Nevada corporation. The name of
the Company after the merger was changed to Tom Brown Drilling Company, Inc. and
to Tom Brown, Inc. in 1971. In February 1987, the Company changed its state of
incorporation from Nevada to Delaware. In 1999, the Company relocated its
headquarters and executive offices to 555 Seventeenth Street, Suite 1850, Denver
Colorado 80202 and its telephone number at that address is (303) 260-5000.
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 Paradox
Basin of Utah and 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 and Canada.
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 and (iii) the drilling
of gas and oil wells.
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 Eastern 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 its
participation as a joint proponent of a plan of reorganization for Presidio Oil
Company in 1996.
BUSINESS STRATEGY
The Company's business strategy is to increase shareholder value through
the discovery, 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 3,054,000 gross
(2,031,000 net) acres (including options) located primarily in the Wind River
and Green River Basins of Wyoming, the Piceance Basin of Colorado, the Paradox
Basin of Colorado and Utah, 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 89% of the net acreage is undeveloped, giving the Company
development drilling leverage to the extent that gas prices increase.
Additionally, by staying focused in its core basins, the Company continues to
develop more effective drilling and completion techniques which can improve
overall economic efficiency.
The Company increased its reserves in 1999 over 1998 by 29%, due primarily
to an acquisition in the Paradox Basin in July, 1999 and due to continued
drilling success in its core areas. Year-end proved reserves
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were 524 billion cubic feet equivalent ("Bcfe"), compared to year-end 1998
reserves of 406 Bcfe. Since December 31, 1995, the Company has increased proved
reserves at a compounded annual growth rate of 23%, or from 188 Bcfe to 524
Bcfe.
Reserve replacement for 1999 was 340% from all sources and 123% from
additions and revisions only. Finding cost was $0.70 per Mcfe for the year from
all sources and $0.79 per Mcfe from additions and revisions. The Company's
reserve to production ratio increased to 10.6 years at year-end 1999 from 9.7
years at year-end 1998. In addition to increasing reserves, the Company also
increased its production 17% from 42.0 Bcfe in 1998 to 49.2 Bcfe in 1999.
The Company markets a portion of its operated gas production and third
party gas in the Rocky Mountains through Retex, Inc. ("Retex"), the Company's
wholly-owned marketing subsidiary.
Wildhorse Energy Partners, LLC ("Wildhorse") conducts gas gathering and
processing activities in the Rocky Mountains. Wildhorse is owned 55% by Kinder
Morgan, Inc. ("KM") and 45% by the Company.
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.
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, Paradox, and Piceance Basins
The Wind River and Green River Basins of Wyoming, the Piceance Basin of
Colorado, and the Paradox Basin of Colorado and Utah account for a major portion
of the Company's current and anticipated exploration and development activities
with approximately 78% of the Company's proved reserves at December 31, 1999.
The Company owns interests in 913 producing wells in these basins that averaged
net daily production of 82 Mmcfe for 1999. The Company has approximately
2,064,000 gross (1,622,000 net) developed and undeveloped acres in these basins,
including option acreage of approximately 939,000 gross (767,000 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. 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. Additionally, the Enron-Burlington Lost Creek Pipeline
should be operational by the third quarter of 2000 which will also help to
alleviate Wind River Basin constraints.
Permian and Val Verde Basins
The Permian and Val Verde Basins accounted for approximately 12% of the
Company's proved reserves at December 31, 1999. The Company's share of
production from these basins averaged 32 Mmcfepd of natural gas for 1999. The
Company holds a 50% working interest in approximately 36,000 gross acres and 45
producing wells in the Val Verde Basin. The Permian Basin contains significant
oil reserves for the Company, located primarily in the Spraberry Field. The
Company owns interests in 425 wells and has approximately 32,000 net developed
and undeveloped acres in this basin.
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East Texas Basin
Together with Marathon Oil Corporation, the Company began a seven well
developmental drilling program in the Mimms Creek Field in Freestone County,
Texas with the successful drilling of a Bossier Sand well in late 1999. The
Company owns working interests ranging from 50% to 62.5% in the drilling
program. The Company has acquired approximately 16,000 net acres in the James
Lime (horizontal) Trend of the East Texas Basin, and is currently evaluating its
acreage position for potential drilling activity.
BUSINESS DEVELOPMENTS
Current Developments in the Gas and Oil Business
ACQUISITION OF THE ASSETS OF UNOCAL CORPORATION
In July 1999, the Company completed an acquisition of substantially all of
the Rocky Mountain oil and gas assets of Unocal Corporation ("Unocal") for 5.8
million shares of common stock and $5 million in cash for a total purchase price
of $68.5 million ($60.9 million after deducting normal purchase price
adjustments.)
The Unocal oil and gas assets are primarily located in the Paradox Basin of
southwestern Colorado and southeastern Utah. These assets and properties will
compliment the Company's 163,000 net undeveloped acres in the Paradox Basin.
Additionally, the discretionary cash flow provided by the Unocal assets and
properties was accretive to the Company in 1999.
Included in the acquisition is the Lisbon Plant, a modern sophisticated
cyrogenic (60 million cubic feet per day capacity) natural gas processing plant
that extracts natural gas liquids and merchantable helium; and separates carbon
dioxide, hydrogen sulfide and nitrogen from the raw gas stream. The average net
sales from the Unocal properties in 1998 was approximately 18 million cubic feet
per day of natural gas, 290 barrels of oil per day and 92,000 gallons of gas
plant liquids per day, or approximately 33 million cubic feet equivalent per day
(assuming gas plant liquids and oil converted at 6:1). The net proved reserves
of these Unocal properties were estimated to be 93.2 billion cubic feet
equivalent of gas as of the closing date of July 1, 1999. Approximately 65,000
net undeveloped acres were also acquired.
ACQUISITION OF ROCKY MOUNTAIN ASSETS
In September 1999, the Company purchased certain Rocky Mountain assets from
an undisclosed seller for approximately $7.7 million in cash. Included in the
acquisition was approximately 9.7 Bcfe of proved reserves and 34,000 net acres
in the Greater Green River Basin of Wyoming.
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. The purchase
price for these assets was approximately $35.5 million.
Current Developments in the Marketing, Gathering and Processing Business
In September 1999, KM became the operator of, and 55% partner in, Wildhorse
as a result of a merger with KN Energy, Inc. ("KNE"). Wildhorse was formed in
connection with the Company's 1996 acquisition of KN Production Company, the
wholly-owned oil and gas production subsidiary of KNE. Wildhorse was created to
provide services related to natural gas, natural gas liquids and other natural
gas products, including gathering, processing and storage services and field
services. The Company has owned 45% of Wildhorse since its inception. The
business and affairs of Wildhorse are managed by KM under the direction of an
operating team consisting of two representatives appointed by the Company and
two representatives appointed by KM.
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Effective September 1, 1999, Wildhorse assigned 100% of its marketing
operations to Retex, the Company's wholly-owned marketing subsidiary.
Additionally, firm transportation contracts were assigned 55% to KM and 45%
remained in Retex.
Current Developments in the Drilling Business
ACQUISITION OF ASSETS OF W. E. SAUER COMPANIES, LLC
On January 7, 1998, the Company completed the acquisition of all of the
drilling assets of W. E. Sauer Companies L.L.C. of Casper, Wyoming for
approximately $8.1 million. The assets include five drilling rigs, tubular
goods, a yard and related assets. In 1999, Sauer acquired an additional drilling
rig for approximately $1.1 million. The Company operates the assets in its
subsidiary, Sauer Drilling Company ("Sauer"), 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 1999, 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 $3.09 per million British thermal unit ("Mmbtu") in
November 1999 to a low of $1.67 per Mmbtu in March 1999. Additionally, the
Company produced approximately 65% of its gas production in the Rocky Mountain
area where the price of gas varied as compared to NYMEX prices from $.41 per
Mmbtu below NYMEX prices in August 1999 to virtually no basis differential in
January 1999.
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.
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, crude oil and natural gas liquids for each
of the years ended December 31, 1999, 1998 and 1997.
YEARS ENDED DECEMBER 31,
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1999 1998 1997
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Production Volumes:
Natural Gas (MMcf)........................................ 40,514 35,887 31,842
Crude Oil (MBbls)(1)...................................... 1,444 1,027 1,159
Net Average Daily Production Volumes:
Natural Gas (Mcf)......................................... 110,997 98,321 87,238
Crude Oil (Bbls)(1)....................................... 3,956 2,814 3,175
Average Sales Prices:
Natural Gas (per Mcf)..................................... $ 2.04 $ 1.85 $ 2.18
Crude Oil (per Bbl)(1).................................... $ 15.20 $ 11.37 $ 18.02
Average Production Cost (per Mcfe)(2)....................... $ .58 $ .52 $ .56
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(1) Oil volumes include natural gas liquids, which were 535,000 barrels for
1999. For years prior to 1999, natural gas liquids were insignificant.
(2) 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 and natural gas liquids to one Mcf of gas.)
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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.
Retex 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 Retex may derive.
EXECUTIVE OFFICERS OF THE COMPANY
The executive officers of the Company on March 17, 2000 were as follows:
NAME AGE POSITION WITH COMPANY SINCE
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Donald L. Evans...................... 53 Chairman of the Board and Chief Executive 1976
Officer
James D. Lightner.................... 47 President and Director 1999
Thomas W. Dyk........................ 46 Executive Vice President and Chief 1998
Operating Officer
Peter R. Scherer..................... 43 Executive Vice President 1986
Daniel G. Blanchard.................. 39 Vice President and Chief Financial Officer 1999
Hilary G. Dussing.................... 42 Vice President -- Exploration 1999
Rodney G. Mellot..................... 42 Vice President -- Land and Business 1999
Development
Bruce R. DeBoer...................... 47 Vice President, General Counsel and 1997
Secretary
Jack F. Harper....................... 28 Vice President-Investor Relations and 1999
Treasurer
R. Kim Harris........................ 43 Vice President-Finance and Controller 1986
B. Jack Reed......................... 50 Vice President-Human Resources 1990
Each executive officer is elected annually by the Company's Board of
Directors to serve at the Board's discretion.
EMPLOYEES
At December 31, 1999, the Company had 230 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
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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 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 ("Rocno"), a wholly-owned subsidiary of the Company, is a
party to a trust agreement in connection with the environmental clean-up plan
for the Sheridan Superfund Site in Waller County, Texas. See Item 3, Legal
Proceedings.
Indian Lands
The Company's Muddy Ridge and Pavillion Fields are located on the Wind
River Indian Reservation. The Eastern Shoshone and Northern Arapaho Tribes
regulate certain aspects of the production and sale of
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natural gas and crude oil, and the drilling 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 an additional
ten-year term in 1992, effective as of June 23, 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.
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 Eastern 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.
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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, 1999.
Excluded from the table are approximately 939,000 gross (767,000 net) acres in
Wyoming under gas and oil option agreements acquired from certain Indian tribes.
DEVELOPED UNDEVELOPED
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GROSS NET GROSS NET
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Colorado.................................... 108,400 85,718 435,673 379,675
Kansas...................................... 1,961 1,563 1,802 1,614
Louisiana................................... 11,994 4,060 7,753 2,073
Michigan.................................... -- -- 303 121
Mississippi................................. 756 362 4,375 470
Montana..................................... 4,678 718 175,464 37,467
Nebraska.................................... -- -- 32,895 32,146
New Mexico.................................. 15,577 3,981 2,440 2,036
North Dakota................................ 600 -- 7,119 513
Oklahoma.................................... 33,940 11,354 6,676 3,187
Texas....................................... 110,254 39,064 58,632 29,564
Utah........................................ 5,402 4,581 24,854 20,524
West Virginia............................... 3,673 1,095 157,131 81,018
Wyoming..................................... 143,954 60,875 758,521 459,908
Other....................................... 360 58 10 2
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Total............................. 441,549 213,429 1,673,648 1,050,318
======= ======= ========= =========
"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.
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, 1999 and 1998, and by Ryder Scott and Williamson Petroleum
Consultants, Inc. at December 31, 1997, (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.
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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, 1999.
PRODUCTIVE WELLS
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GROSS NET
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GAS OIL GAS OIL
----- --- ------ ------
Colorado.............................................. 451 42 215.56 17.79
Louisiana............................................. 48 36 11.59 13.67
New Mexico............................................ 34 28 7.27 12.15
North Dakota.......................................... 6 5 2.13 3.49
Oklahoma.............................................. 127 34 30.37 9.38
Utah.................................................. 8 22 7.1 21.17
Texas................................................. 116 292 50.38 98.77
West Virginia......................................... 56 -- 18.39 --
Wyoming............................................... 488 151 172.19 42.59
Other................................................. 17 13 4.65 .74
----- --- ------ ------
Total....................................... 1,351 623 519.63 219.75
===== === ====== ======
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.
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,
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1999 1998 1997
------------------- ------------------- -------------------
TYPE OF WELL GROSS NET NET% GROSS NET NET% GROSS NET NET%
- ------------ ----- ---- ---- ----- ---- ---- ----- ---- ----
Exploratory
Gas............................. 2 .8 20 8 3.0 46 -- -- --
Oil............................. -- -- -- -- -- -- -- -- --
Dry............................. 4 3.2 80 7 4.5 54 7 3.7 100
-- ---- --- -- ---- --- -- ---- ---
6 4.0 100 15 7.5 100 7 3.7 100
Development
Gas............................. 37 16.3 99 52 31.4 78 72 27.7 89
Oil............................. 1 0.2 1 16 4.2 11 7 2.2 7
Dry............................. -- -- -- 6 4.2 11 3 1.1 4
-- ---- --- -- ---- --- -- ---- ---
38 16.5 100 74 39.8 100 82 31.0 100
Total............................. 44 20.5 89 47.3 89 34.7
== ==== == ==== == ====
At December 31, 1999, 18 gross (6.1 net) development wells and 1 gross (.9
net) exploration well were in various stages of drilling and completion in Texas
and Wyoming.
OTHER PROPERTIES
The Company leases its home office facilities in Denver, Colorado. The
lease covers approximately 56,500 square feet and expires January 31, 2004. Of
this amount, the Company subleases 7,246 square feet under an agreement that
expires January 31, 2004.
The Company also leases office facilities in Midland, Texas. The lease
covers approximately 33,150 square feet for a term of five years and expires
December 31, 2003.
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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 subleased approximately 41,000 square feet of leased office
space, which was obtained through the Presidio acquisition. Both the lease and
sublease expired 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 was a defendant in a complaint filed by the United States of
America which, among other things, alleged that Rocno and approximately 117
other companies 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"). Effective August
31, 1989, Rocno and thirty-six other defendants executed 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 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, 1999. 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, 1999.
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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, 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
March 31, 1999.............................................. 14 1/16 8 1/4
June 30, 1999............................................... 15 9/16 11 15/16
September 30, 1999.......................................... 18 5/8 12 15/16
December 31, 1999........................................... 16 5/8 11 11/16
On March 17, 2000 the last sale price of the Company's Common Stock, as
reported by the NASDAQ National Market System, was $16.125 per share.
The transfer agent for the Company's Common Stock is Boston EquiServe,
L.P., Canton, Massachusetts.
On December 31, 1999, the outstanding shares of the Company's Common Stock
(35,308,489 shares) were held by approximately 2,149 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.
In July 1999, the Company completed an acquisition of substantially all of
the Rocky Mountain oil and gas assets of Unocal Corporation for 5.8 million
shares of common stock and $5 million in cash.
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.
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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.
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
Unocal Acquisition in July 1999, the Genesis Acquisition in October 1997, the
Presidio Acquisition in December 1996, and the KNPC Acquisition in January 1996.
(See Note 3 to Notes to Consolidated Financial Statements of the Company
included elsewhere herein.)
YEARS ENDED DECEMBER 31,
--------------------------------------------------------
1999 1998 1997 1996 1995
-------- -------- --------- ---------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Revenues(1).............................. $214,850 $131,330 $ 126,375 $ 65,915 $ 40,536
======== ======== ========= ========== =========
Net income (loss) attributable to common
stock.................................. 5,007 (45,233) 6,860 6,263 5,785
======== ======== ========= ========== =========
Weighted average number of common shares
outstanding
Basic.................................. 32,228 29,251 25,110 21,116 16,292
======== ======== ========= ========== =========
Diluted................................ 32,466 29,251 26,407 22,525 16,887
======== ======== ========= ========== =========
Net income (loss) per common share
Basic.................................. .16 (1.55) .27 .30 .36
======== ======== ========= ========== =========
Diluted................................ .15 (1.55) .26 .28 .34
======== ======== ========= ========== =========
Total assets............................. 536,299 441,882 450,926 406,374 164,174
======== ======== ========= ========== =========
Long-term debt, net of current
maturities............................. 81,000 55,000 23,000 119,000 --
======== ======== ========= ========== =========
Other Financial Data:
EBITDAX(2)............................. 74,438 49,348 69,716 33,173 18,183
Net cash provided by operating
activities before changes in working
capital(2).......................... 66,710 43,544 59,652 31,902 12,235
Net cash provided by operating
activities.......................... 45,746 69,240 47,600 29,114 10,127
Net cash used in investing
activities.......................... (61,889) (98,774) (86,672) (131,434) (72,200)
Net cash provided by financing
activities.......................... 25,983 25,667 25,105 117,842 47,908
- ---------------
(1) Certain reclasses have been made to amounts reported in previous years to
conform to the 1999 presentation.
(2) EBITDAX reflects income before income taxes, plus interest expense,
depreciation, depletion and amortization expense, exploration costs and
impairments of leasehold costs. EBITDAX and cash flows from 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 $51.3
million and $8.4 million, respectively, for impairment of gas and oil
properties, which were non-cash charges.
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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,
-----------------------------------------------
1999 1998 1997 1996 1995
------- ------- ------- ------- -------
Volumes sold:
Gas (Mmcf)................................. 40,514 35,887 31,842 16,762 10,585
Oil (MBbls)(1)............................. 1,444 1,027 1,159 545 387
Proved reserves at period end:
Gas (Mmcf)................................. 445,943 372,022 347,104 359,167 163,303
Oil (MBbls)(1)............................. 13,001 5,682 7,227 12,306 4,068
- ---------------
(1) Oil volumes include natural gas liquids ("NGL") for the periods shown. For
1999, there were 535,000 barrels of NGL production and 6,266,000 barrels of
NGL reserves. NGL volumes in years prior to 1999 were insignificant.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
The Company's results of operations were favorably impacted in 1999 due to
a mid-year acquisition of properties and a cyrogenic natural gas processing
plant from Unocal and due to successful drilling results.
Revenues
During 1999, revenues from gas, oil and natural gas liquids production
increased 34% to $104.4 million, as compared to $78.1 million in 1998. Such
increase was the result of an increase in (i) average gas prices received by the
Company from $1.85 per Mcf in 1998 to $2.04 per Mcf in 1999, which increased
revenues $6.8 million, (ii) average oil and natural gas liquids prices received
from $11.37 to $15.20 which increased revenues $3.9 million, (iii) gas sales
volumes of 13% to 40.5 Bcf which increased revenues by $9.4 million due
primarily to the Unocal Acquisition and to successful drilling results, and (iv)
oil and natural gas liquids sales volumes of 41% to 1.4 million barrels, which
increased revenues by $6.2 million due primarily to the Unocal Acquisition.
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.
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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,
------------------------------
1999 1998 1997
-------- -------- --------
(IN THOUSANDS)
Revenues:
Natural gas sales.................................. $ 82,479 $ 66,392 $ 69,332
Crude oil sales(1)................................. 21,952 11,680 20,887
Marketing, gathering and processing................ 102,621 47,981 34,998
Drilling........................................... 5,645 4,561 --
Interest income and other.......................... 2,153 716 1,158
-------- -------- --------
Total revenues..................................... $214,850 $131,330 $126,375
======== ======== ========
Net income (loss) attributable to common stock....... $ 5,007 $(45,233) $ 6,860
======== ======== ========
YEARS ENDED DECEMBER 31,
---------------------------
1999 1998 1997
------- ------- -------
Natural gas production sold (Mmcf)...................... 40,514 35,887 31,842
Crude oil production (Mbbls)(1)......................... 1,444 1,027 1,159
Average natural gas sales price ($/Mcf)................. $ 2.04 $ 1.85 $ 2.18
Average crude oil sales price ($/Bbl)................... $ 15.20 $ 11.37 $ 18.02
- ---------------
(1) Crude oil includes natural gas liquids ("NGL") for all years presented. For
1999, NGL volumes were 535,000 barrels and NGL sales were $6,509,000,
resulting from a mid-year property acquisition from Unocal. For years prior
to 1999, NGL volumes and sales were insignificant.
Marketing, gathering and processing revenues in 1998 and 1997 reflect the
Company's 45% share of such revenues generated by Wildhorse in those years.
Effective September 1, 1999 Wildhorse assigned 100% of its marketing operations
to Retex. As such, marketing, gathering and processing revenues in 1999 reflect
the Company's 45% share of such revenues generated by Wildhorse in 1999 along
with marketing revenues generated by Retex for the period September 1, 1999
through December 31, 1999.
The 114% increase in marketing, gathering and processing revenues in 1999
compared to 1998 is composed of a 136% increase in marketing revenues and a 30%
increase in gathering and processing revenues. The increase in marketing
revenues is due primarily to 1) additional revenues recognized as a result of
the assignment of Wildhorse's marketing operations to Retex as discussed above
and 2) an increase in the volume of gas marketed for third parties. The increase
in gathering and processing revenues is due primarily to helium sales resulting
from the Unocal Acquisition.
The 37% increase in marketing, gathering and processing revenues in 1998
compared to 1997 is composed of a 36% increase in marketing revenues and a 43%
increase in gathering and processing revenues. The increase in marketing
revenues is due primarily to 1) additional volumes of gas marketed as a result
of an increase in the Company's production and 2) marketing of additional third
party gas in 1998. The increase in gathering and processing revenues is due
primarily to Wildhorse's acquisition of Interenergy Corporation (see Note 3 to
the Consolidated Financial Statements).
In 1999 the Company sold its interest in certain properties in Colorado for
$2.0 million and recorded a gain of $1.2 million on the sale. 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.
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Costs and Expenses
Expenses related to gas and oil production and production taxes increased
29% from 1998 to 1999 due primarily to the acquisition of gas and oil properties
and a cyrogenic natural gas processing plant in July 1999 from Unocal. On an
Mcfe basis, gas and oil production costs increased to $.38 in 1999 from $.35 in
1998, due to the cost of operating the plant. From 1997 to 1998, these expenses
remained virtually unchanged. In 1997, gas and oil production cost was $.37.
Taxes on gas and oil production increased 32% from 1998 to 1999 as a result
of the higher gas and oil sales but remained constant as a percentage of sales.
Production taxes in 1998 increased slightly from 1997, but as a percentage of
sales, increased from 8.2% to 9.6%. This change reflects an increase in gas
sales in the Wind River Basin beginning in 1998 where the Company experiences
higher production taxes as compared to its other areas of operations.
The Company's depletion, depreciation and amortization rates per Mcfe were
$.90, $1.06 and $.93 for years 1999, 1998 and 1997, respectively. The decrease
from 1998 to 1999 was primarily due to (i) lower finding and development costs
associated with 1999 reserve additions and (ii) the impairment of properties in
1998. The increase from 1997 to 1998 was primarily caused by the adverse effect
on reserves of oil prices at the end of 1998, and accordingly, the Company
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.)
Cost of gas sold has increased substantially each year from 1997 to 1999
consistent with the increases in related revenues. Profit margins were $5.3
million in 1999 compared to a loss of $0.5 million in 1998 and a profit of $5.3
million in 1997. Lower transportation rates in 1999 and the addition of helium
sales in connection with the plant acquired from Unocal accounted for the
increase from 1998 to 1999. The decrease in profit margin from 1997 to 1998 was
due to lower gathering margins in 1998 and an increase in transportation costs
relative to market differentials.
Expenses associated with the Company's exploration activities were $10.0
million, $17.3 million and $13.2 million for the years 1999, 1998 and 1997,
respectively. In 1998, the Company increased its exploration program to more
fully explore the Wind River Basin of Wyoming. In 1999, the Company's
exploration expenditures decreased in comparison to 1998 due to an overall
reduction in capital spending levels for drilling and completion activity.
Impairments of leasehold costs increased to $3.6 million in 1999 from $3.2
million and $1.4 million in 1998 and 1997, respectively. The year-over-year
increases reflect amounts of leasehold expirations from year to year.
General and administrative expenses have increased from year to year as a
result of the Company's higher level of operations. On an Mcfe basis, general
and administrative expenses were $.19, $.17, and $.13 for the years 1999, 1998
and 1997, respectively reflecting added personnel each year, and in 1999, costs
incurred in the Company's decision to relocate its corporate headquarters to
Denver, Colorado. Such amount in 1999 was $2.1 million, or $.04 per Mcfe. (See
Note 2 to the Notes to Consolidated Financial Statements of the Company.)
Interest expense increased $1.3 million in 1999 to $5.6 million compared to
$4.3 million in 1998 due to increased debt levels during the year. Interest
expense was lower in 1998 by $1.6 million from 1997 due to the Company's Common
Stock offering in October, 1997 and subsequent repayment of debt.
The Company recorded income tax provisions of $4.3 million and $4.4 million
in 1999 and 1997, respectively, and income tax benefit of $27.9 million in 1998,
resulting in effective tax rates of 38.9%, 39.0% and 33.7%, respectively. At
December 31, 1999 the Company has a net operating loss carryforward of
approximately $73.2 million available to offset future taxable income. The
Company believes it will generate sufficient taxable income in 2000 to utilize
the $17.6 million net operating loss carryforward that will expire at the ended
of 2000. If the Company is unable to generate sufficient taxable income in 2000
to utilize the $17.6 million net operating loss carryforward, it will enact such
other tax planning strategies necessary to
17
18
utilize such benefit (such as the advance gas sale utilized in 1998 - see Note 6
to the Notes to Consolidated Financial Statements).
The Company's net deferred tax asset was $28.6 million at December 31,
1999. A valuation allowance of approximately $2.0 million at December 31, 1999
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 and other deferred tax assets to realize the benefit
attributable to the net operating loss carryforwards 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.
Capital and Exploration Expenditures
The Company's capital and exploration expenditures and sources of financing
for the years ended December 31, 1999, 1998 and 1997 are as follows:
1999 1998 1997
------ ----- ------
(IN MILLIONS)
CAPITAL AND EXPLORATION EXPENDITURES:
ACQUISITIONS:
Genesis................................................... $ -- $ -- $ 35.5
Interenergy............................................... -- -- 10.5
Sauer Drilling Company.................................... 1.4 8.1 --
Unocal.................................................... 60.9 -- --
Other Rocky Mountain Assets............................... 8.2 -- --
Other..................................................... 2.5 -- --
Exploration costs........................................... 12.0 22.8 16.0
Development costs........................................... 33.2 49.3 33.8
Acreage..................................................... 2.5 3.3 6.1
Gas gathering and processing................................ 2.7 8.6 6.7
Other....................................................... 1.7 1.2 3.5
------ ----- ------
$125.1 $93.3 $112.1
====== ===== ======
FINANCING SOURCES:
Common stock issued......................................... $ 65.2 $ .6 $123.8
Net long term bank debt..................................... 26.0 32.0 (96.0)
Advances from gas purchasers................................ (24.3) 24.3 --
Proceeds from sale of assets................................ 2.6 1.9 12.6
Cash flow from operations before changes in working
capital................................................... 66.7 43.5 59.7
Working capital and other................................... (11.1) (9.0) 12.0
------ ----- ------
$125.1 $93.3 $112.1
====== ===== ======
The Company anticipates capital expenditures of approximately $86.0 million
in 2000, $81.0 million allocated to exploration and development activity. 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
18
19
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 after changes in
working capital was $45.7 million for 1999 as compared to $69.2 million and
$47.6 million in 1998 and 1997, respectively. The decrease in 1999 and the
increase in 1998 was due primarily to the receipt of $24.3 million from gas
purchasers as advances in 1998. In July 1999, the Company completed an
acquisition of substantially all of the Rocky Mountain oil and gas assets of
Unocal Corporation for 5.8 million shares of common stock and $5 million in
cash.
Advance From Gas Purchasers
The Company sold 35 Mmbtu per day 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.
Bank Credit Facility
The Company's Credit Facility provides for a $100 million revolving line of
credit with a current borrowing base of $190 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, 1999 has not yet been made.
At December 31, 1999, the aggregate outstanding balance under the Credit
Facility was $81 million, bearing interest at 6.9% per annum. The amount
available for borrowing under the Credit Facility at December 31, 1999 was $19
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 all covenants
contained in the Credit Facility at December 31, 1999. 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 an applicable margin or (ii) the agent bank's Eurodollar rate, plus
an applicable margin. (See Note 4 to Notes to Consolidated Financial Statements
of the Company.)
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 provides gathering, processing and storage to Rocky Mountain gas
and oil producers. During 1999, the Company's share of Wildhorse's investments
approximated $2.3 million for gas gathering and processing assets. The Company
(45 percent) and KM (55 percent) jointly own Wildhorse.
The Company dedicated significant amounts of its Rocky Mountain gas
production to Wildhorse for gathering, and processing.
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. During 1999, the
average prices received for gas and oil by the Company were $2.04 per Mcf and
$15.20 per barrel, respectively, as compared to $1.85 Mcf and $11.37 per barrel
in 1998 and $2.18 per Mcf and $18.02 per barrel in 1997.
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20
Year 2000
The Company previously performed a review of its internal informational
systems for year 2000 ("Y2K") automation compliance through a Company-wide
effort to address Y2K system issues. Such review included verification of Y2K
readiness of the Company's key vendors and purchasers. The Company has not
encountered any material Y2K compliance problems regarding the above. Costs
incurred to become Y2K compliant were minimal.
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 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 all fiscal
quarters of fiscal years beginning after June 15, 2000 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.
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
adopted SOP 98-1 in the first quarter of fiscal 1999 and adoption did 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.
20
21
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.
Interest Rate Risk
At December 31, 1999, the Company had $81 million outstanding under its
credit facility at an average interest rate of 6.9%. 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 an applicable margin or (ii) the agent bank's Eurodollar rate, plus an
applicable margin. 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 2000, the impact on interest expense of a ten percent change
in the average interest rate would be approximately $560,000. As the interest
rate is variable and is reflective of current market conditions, the carrying
value approximates the fair value.
21
22
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Report of Independent Public Accountants.................... 28
Consolidated Balance Sheets, December 31, 1999 and 1998..... 29
Consolidated Statements of Operations, Years ended December
31, 1999, 1998 and 1997................................... 31
Consolidated Statements of Changes in Stockholders' Equity,
Years ended December 31, 1999, 1998 and 1997.............. 32
Consolidated Statements of Cash Flows, Years ended December
31, 1999, 1998 and 1997................................... 33
Notes to Consolidated Financial Statements.................. 35
22
23
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, 1999 and 1998,
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, 1999. 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 auditing standards generally
accepted in the United States. 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, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999, in conformity with accounting principles generally accepted
in the United States.
ARTHUR ANDERSEN LLP
Houston, Texas
February 25, 2000
23
24
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
DECEMBER 31,
--------------------
1999 1998
-------- ---------
(IN THOUSANDS)
CURRENT ASSETS:
Cash and cash equivalents................................. $ 12,510 $ 2,670
Accounts receivable....................................... 53,646 32,390
Inventories............................................... 828 532
Deferred income taxes..................................... -- 8,585
Other..................................................... 1,625 260
-------- ---------
Total current assets.............................. 68,609 44,437
-------- ---------
PROPERTY AND EQUIPMENT, AT COST:
Gas and oil properties, successful efforts method of
accounting............................................. 470,461 387,336
Gas gathering and processing and other plant.............. 71,657 51,561
Other..................................................... 23,027 20,340
-------- ---------
Total property and equipment...................... 565,145 459,237
Less: Accumulated depreciation, depletion and
amortization........................................... 133,342 92,232
-------- ---------
Net property and equipment........................ 431,803 367,005
-------- ---------
OTHER ASSETS:
Deferred income taxes, net................................ 28,625 23,429
Other assets.............................................. 7,262 7,011
-------- ---------
Total other assets................................ 35,887 30,440
-------- ---------
$536,299 $ 441,882
======== =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable.......................................... $ 39,489 $ 23,124
Accrued expenses.......................................... 9,763 4,754
Advances from gas purchasers.............................. -- 24,529
-------- ---------
Total current liabilities......................... 49,252 52,407
-------- ---------
BANK DEBT................................................... 81,000 55,000
-------- ---------
OTHER NON-CURRENT LIABILITIES............................... 3,950 2,725
-------- ---------
COMMITMENTS AND CONTINGENCIES (Note 12)
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 55,000,000 shares;
Outstanding 35,308,489 shares and 29,259,989 shares,
respectively.......................................... 3,531 2,926
Additional paid-in capital................................ 495,817 431,082
Accumulated deficit....................................... (97,351) (102,358)
-------- ---------
Total stockholders' equity........................ 402,097 331,750
-------- ---------
$536,299 $ 441,882
======== =========
See accompanying notes to consolidated financial statements.
24
25
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31,
----------------------------------------
1999 1998 1997
---------- ------------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
REVENUES:
Gas, oil and natural gas liquids sales.................. $104,431 $ 78,072 $90,219
Marketing, gathering and processing..................... 102,621 47,981 34,998
Drilling................................................ 5,645 4,561 --
Interest income and other............................... 2,153 716 1,158
-------- ----------- -------
Total revenues.................................. 214,850 131,330 126,375
-------- ----------- -------
COSTS AND EXPENSES:
Gas and oil production.................................. 18,446 14,522 14,336
Taxes on gas and oil production......................... 9,934 7,512 7,437
Cost of gas sold........................................ 97,292 48,442 29,734
Drilling operations..................................... 5,237 4,367 --
Exploration costs....................................... 10,013 17,274 13,222
Impairments of leasehold costs.......................... 3,600 3,215 1,350
General and administrative.............................. 9,503 7,139 5,152
Depreciation, depletion and amortization................ 44,215 44,575 36,230
Impairment of gas and oil properties.................... -- 51,344 --
Interest expense........................................ 5,560 4,301 5,920
-------- ----------- -------
Total costs and expenses........................ 203,800 202,691 113,381
-------- ----------- -------
Income (loss) before income taxes............... 11,050 (71,361) 12,994
Income tax benefit (provision)
Current................................................. (903) (1,611) (1,026)
Deferred................................................ (3,390) 29,489 (3,358)
-------- ----------- -------
Net income (loss)......................................... 6,757 (43,483) 8,610
Preferred stock dividends................................. (1,750) (1,750) (1,750)
-------- ----------- -------
Net income (loss) attributable to common stock............ $ 5,007 $ (45,233) $ 6,860
======== =========== =======
Weighted average number of common shares outstanding:
Basic................................................... 32,228 29,251 25,110
======== =========== =======
Diluted................................................. 32,466 29,251 26,407
======== =========== =======
Net income (loss) per common share:
Basic................................................... $ .16 $ (1.55) $ .27
======== =========== =======
Diluted................................................. $ .15 $ (1.55) $ .26
======== =========== =======
See accompanying notes to consolidated financial statements.
25
26
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
PREFERRED STOCK COMMON STOCK ADDITIONAL TOTAL
--------------- --------------- PAID-IN ACCUMULATED STOCKHOLDERS'
SHARES AMOUNT SHARES AMOUNT CAPITAL DEFICIT EQUITY
------ ------ ------ ------ ---------- ----------- -------------
(IN THOUSANDS)
BALANCE AS OF DECEMBER 31,
1996......................... 1,000 $100 23,898 $2,390 $307,631 $ (63,985) $246,136
Stock options exercised........ -- -- 244 24 1,558 -- 1,582
Common stock issuance.......... -- -- 5,068 507 121,705 -- 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......................... 1,000 100 29,210 2,921 430,502 (57,125) 376,398
Stock options exercised........ -- -- 50 5 580 -- 585
Net loss....................... -- -- -- -- -- (43,483) (43,483)
Preferred stock dividends...... -- -- -- -- -- (1,750) (1,750)
----- ---- ------ ------ -------- --------- --------
BALANCE AS OF DECEMBER 31,
1998......................... 1,000 100 29,260 2,926 431,082 (102,358) 331,750
Stock options exercised........ -- -- 248 25 1,707 -- 1,732
Common stock issuance.......... -- -- 5,800 580 62,935 -- 63,515
Unrealized gain on marketable
securities................... -- -- -- -- 93 -- 93
Net income..................... -- -- -- -- -- 6,757 6,757
Preferred stock dividends...... -- -- -- -- -- (1,750) (1,750)
----- ---- ------ ------ -------- --------- --------
BALANCE AS OF DECEMBER 31,
1999......................... 1,000 $100 35,308 $3,531 $495,817 $ (97,351) $402,097
===== ==== ====== ====== ======== ========= ========
See accompanying notes to consolidated financial statements.
26
27
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31,
-------------------------------
1999 1998 1997
-------- -------- ---------
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)......................................... $ 6,757 $(43,483) $ 8,610
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization................ 44,215 44,575 36,230
(Gain) loss on sales of assets.......................... (1,265) 27 (19)
Impairment of gas and oil properties.................... -- 51,344 --
Deferred tax provision (benefit)........................ 3,390 (29,408) 259
Exploration costs....................................... 10,013 17,274 13,222
Impairments of leasehold costs.......................... 3,600 3,215 1,350
-------- -------- ---------
66,710 43,544 59,652
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable........... (19,140) 8,559 (7,869)
(Increase) in inventories............................ (296) (167) (63)
(Increase) decrease in other current assets.......... (616) 11 618
Increase (decrease) in accounts payable and accrued
expenses........................................... 22,644 (4,451) (2,847)
(Increase) decrease in other assets, net............. 973 (2,785) (1,891)
Advances from gas purchasers......................... (24,529) 24,529 --
-------- -------- ---------
Net cash provided by operating activities................... $ 45,746 $ 69,240 $ 47,600
-------- -------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sales of assets............................. $ 2,573 $ 1,870 $ 12,635
Capital and exploration expenditures...................... (63,072) (93,274) (106,805)
Changes in accounts payable and accrued expenses for
capital expenditures.................................... (1,389) (7,370) 7,498
-------- -------- ---------
Net cash used in investing activities....................... (61,888) (98,774) (86,672)
-------- -------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of common stock.................... -- -- 121,665
Borrowings of long-term bank debt......................... 26,000 106,000 27,000
Repayments of long-term bank debt......................... -- (74,000) (123,000)
Repayments of note payable, current....................... -- (5,168) --
Preferred stock dividends................................. (1,750) (1,750) (1,750)
Proceeds from exercise of stock options................... 1,732 585 1,582
Stock issuance costs...................................... -- -- (392)
-------- -------- ---------
Net cash provided by financing activities................... 25,982 25,667 25,105
-------- -------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........ 9,840 (3,867) (13,967)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR.............. 2,670 6,537 20,504
-------- -------- ---------
CASH AND CASH EQUIVALENTS AT END OF YEAR.................... $ 12,510 $ 2,670 $ 6,537
======== ======== =========
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest.................................................. $ 4,051 $ 3,985 $ 6,027
Income taxes.............................................. -- 308 429
Supplemental schedule of noncash investing and financing
activities: (see Notes 2 and 3)
Common stock issued as consideration in connection with
Unocal Acquisition...................................... $ 63,516 $ -- $ --
Common stock received for outstanding receivable.......... 700 -- --
Debt assumed in connection with acquisition of Interenergy
Corporation............................................. -- -- 5,200
See accompanying notes to consolidated financial statements.
27
28
TOM BROWN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(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
Retex, Inc. ("Retex") and Wildhorse Energy Partners, L. L. C. ("Wildhorse") and
(iii) drilling gas and oil wells, primarily through Sauer Drilling Company
("Sauer"). The Company's operations are conducted in the United States and
Canada. The Company's operations are presently focused in the Wind River and
Green River Basins of Wyoming, the Piceance Basin of Colorado, the Paradox Basin
of eastern Utah and western 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 and Canada.
Wildhorse, which is owned fifty-five percent (55%) by Kinder Morgan Inc.
("KM") and forty-five percent (45%) by the Company, was formed by KN Energy,
Inc. ("KNE") (KNE was subsequently acquired by KM) and the Company in January
1996. The business and affairs of Wildhorse are managed by KM under the
direction of an operating team consisting of two representatives appointed by
the Company and two representatives appointed by KM. 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
services related to natural gas, natural gas liquids and other natural gas
products, including gathering, processing and storage services. In September
1999, Wildhorse assigned 100% of its marketing operations to Retex.
Additionally, firm transportation contracts were assigned 55% to KM and 45%
remained in Retex.
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, crude oil and
natural gas liquids 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 (82 percent in 1999 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 1999 presentation.
28
29
TOM BROWN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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,
certain 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.
Maintenance and repairs are charged to expense; renewals and betterments
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 1999 or 1997.
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 on 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. Using year end prices, the Company had net
gas balancing liabilities of
29
30
TOM BROWN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
approximately $1.9 million and $1.4 million associated with approximately 1.3
billion and 1.4 billion cubic feet ("Bcf") of gas at December 31, 1999 and 1998,
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 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.
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative
Instruments and Hedging Activities." SFAS 133 establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded on the
balance sheet as either an asset or liability measured at its fair value. It
also requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement, and requires
that a company must formally document, designate, and assess the effectiveness
of transactions that receive hedge accounting. SFAS 133 is effective for all
fiscal quarters of fiscal years beginning after June 15, 2000. The Company has
not yet quantified the impacts of adopting SFAS 133 on its financial statements
and has not determined the timing of, or method of, adoption of SFAS 133.
However, SFAS 133 could increase volatility in earnings and other comprehensive
income.
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 SFAS No. 123, "Accounting for Stock Based Compensation," on the
Company's results of operations for 1999, 1998 and 1997.
30
31
TOM BROWN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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
Basic earnings per share ("EPS") 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
EPS calculations also give effect to all dilutive potential common shares
outstanding during the period.
The following is a reconciliation of the numerators and denominators used
in the calculation of basic and diluted EPS for the years ended December 31,
1999, 1998 and 1997:
1999 1998 1997
--------------------------- ----------------------------- ---------------------------
NET PER SHARE NET PER SHARE NET PER 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... $5,007 32,228 $.16 $(45,233) 29,251 $(1.55) $6,860 25,110 $.27
Dilutive Securities:
Stock Options............... -- 238 -- -- -- -- -- 1,297 --
------ ------ ---- -------- ------ ------ ------ ------ ----
Diluted EPS:
Net Income (loss)
Attributable to Common
Stock and Assumed Share
Amounts................... $5,007 32,466 $.15 $(45,233) 29,251 $(1.55) $6,860 26,407 $.26
====== ====== ==== ======== ====== ====== ====== ====== ====
Options to purchase 1,447,000 and 90,000 shares of common stock in 1999 and
1997, respectively, were excluded in the computation of diluted earnings per
share because the option exercise price was greater than the average market
price of the Company's common stock. Shares of common stock issuable upon
conversion of preferred stock were excluded in the computation of diluted
earnings per share in any year because their assumed conversion would be
antidilutive. All options to purchase common stock were excluded in the
computation of diluted earnings per share in 1998 because they were antidilutive
as a result of the Company's net loss in that year.
Consolidated Statements of Cash Flows
The Company considers investments with an original maturity of three months
or less when purchased to be cash equivalents. In connection with the
acquisition of Interenergy Corporation ("Interenergy") in December 1997,
Wildhorse assumed $11.5 million in debt, $5.2 million net to the Company. (See
Notes 3 and 4.) In July 1999, the Company issued 5.8 million shares of common
stock valued at $63.5 million to Unocal Corporation as partial consideration for
the acquisition of gas and oil assets (see Note 3). Additionally in June 1999
the Company received shares of stock valued at approximately $700,000 in
settlement of an outstanding receivable from a working interest owner.
31
32
TOM BROWN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Comprehensive Income
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. The only
reconciling item between net income as reflected in the statement of operations
and comprehensive income for the year ended December 31, 1999 was an unrealized
gain on marketable securities of $93,000. There were no such reconciling items
for the years ended December 31, 1998 and 1997.
Exit Costs
In connection with the Company's decision in 1999 to relocate its corporate
headquarters to Denver, Colorado, the Company recognized costs of $2.1 million
as part of general and administrative expenses in 1999. Included in the costs
were actual severance payments made in 1999 of $1.0 million and an accrual for
$.8 million of severance and transition bonus payments to be made in 2000. An
additional accrual of $.3 million was made for future rental obligations for
years 2000 through 2003. The $1.1 million accrual is included in accrued
expenses in the December 31, 1999 consolidated balance sheet.
(3) ACQUISITIONS AND DIVESTITURES
Acquisition of Certain Unocal Rocky Mountain Assets
In July 1999, the Company completed an acquisition of substantially all of
the Rocky Mountain gas and oil assets of Unocal Corporation ("Unocal") for 5.8
million shares of common stock and $5 million in cash for a total purchase price
of $68.5 million ($60.9 million after normal purchase adjustments) ("Unocal
Acquisition"). The Unocal gas and oil assets are primarily located in the
Paradox Basin of southwestern Colorado and southeastern Utah.
The purchase price was allocated as follows:
(IN MILLIONS)
-------------
Gas and oil properties...................................... $37.6
Unproved properties......................................... 2.7
Gas processing plant........................................ 19.9
Oil pipeline................................................ .8
-----
$60.9
=====
Included in the acquisition is the Lisbon Plant, a modern sophisticated
cyrogenic (60 million cubic feet per day capacity) natural gas processing plant
that extracts natural gas liquids and merchantable helium, and separates carbon
dioxide, hydrogen sulfide and nitrogen from the raw gas stream. The average net
production from the Unocal properties in 1998 was approximately 18 million cubic
feet per day of natural gas, 290 barrels of oil per day and 92,000 gallons of
gas plant liquids per day, or approximately 33 million cubic feet equivalent per
day (assuming gas plant liquids and oil converted at 6:1). The net proved
reserves of these Unocal properties were estimated to be 93.2 billion cubic feet
equivalent of gas as of the closing date of July 1, 1999. Approximately 65,000
net undeveloped acres were also acquired.
32
33
TOM BROWN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Pro Forma Information (Unaudited)
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, 1999
and 1998, assuming that the Unocal Acquisition occurred on January 1, 1998.
YEARS ENDED
DECEMBER 31,
-------------------------
1999 1998
----------- -----------
(IN THOUSANDS, EXCEPT FOR
PER SHARE AMOUNTS)
Revenues.................................................... $226,141 $153,832
======== ========
Net income (loss)........................................... $ 9,341 $(40,243)
======== ========
Net income (loss) attributable to common stock.............. $ 7,591 $(41,993)
======== ========
Net income (loss) per common share
Basic..................................................... $ .22 $ (1.20)
======== ========
Diluted................................................... $ .21 $ (1.20)
======== ========
Acquisition of Other Rocky Mountain Assets
In September 1999, the Company purchased certain Rocky Mountain assets from
an undisclosed seller for approximately $7.7 million in cash. Included in the
acquisition was approximately 9.7 Bcfe of proved reserves and 34,000 net acres
in the Greater Green River Basin of Wyoming.
Acquisition of Assets of W. E. Sauer Companies, LLC
In January 1998, the Company completed the acquisition of the drilling
assets of W. E. Sauer Companies L.L.C. of Casper, Wyoming for approximately $8.1
million. The assets include five drilling rigs, tubular goods, a yard and
related assets. The Company operates the assets in its subsidiary, Sauer, 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. 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.
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.
33
34
TOM BROWN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Sale of DJ Basin Properties
In June and October 1999, the Company sold its interest in the DJ Basin of
Colorado for $2.3 million. The properties had a net book value of $1.1 million
and, accordingly, a gain of $1.2 million was recorded on the sale. Proceeds from
the sale of these properties was used to repay a portion of the Company's
outstanding indebtedness under its credit facility existing at such time.
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 existing at such time.
(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 "Credit
Facility") that matures in April 2001. In October 1998, the Company amended the
Credit Facility by increasing the total borrowing amount to $100 million. The
borrowing base increased from $130 million to $190 million in October, 1999, as
a result of the regular June 30 review. The increase was primarily due to the
Unocal Acquisition. 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, 1999 has not yet been made. As of
December 31, 1999, $19 million was available for borrowing under the Credit
Facility.
Borrowings under the 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 an applicable margin
or (ii) the agent bank's Eurodollar rate plus an applicable margin. Interest on
amounts outstanding under the 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, 1999, the outstanding balance was $81 million at an average
interest rate of 6.9%.
The Credit Facility contains certain financial covenants and other
restrictions including a limitation on the Company's ability to pay dividends to
other than the Company's Preferred Stockholders (see Note 7). Financial
covenants of the Credit Facility require the Company to maintain a minimum
consolidated tangible net worth of not less than $300 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 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.
(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
34
35
TOM BROWN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
of 35% in 1999, 1998 and 1997 was used in the following reconciliation of the
Company's effective income tax benefit (provision):
YEARS ENDED DECEMBER 31,
---------------------------
1999 1998 1997
------- ------- -------
(IN THOUSANDS)
Federal income tax benefit (provision) at statutory
rate.................................................. $(3,868) $24,976 $(4,548)
Revisions of previous tax estimates..................... 9 2,130 1,111
Adjustment to valuation allowance....................... 622 2,980 474
Other................................................... (153) (597) (395)
------- ------- -------
(3,390) 29,489 (3,358)
AMT provisions.......................................... -- (380) (403)
State income and franchise taxes........................ (903) (1,231) (623)
------- ------- -------
Income tax expense benefit (provision).................. $(4,293) $27,878 $(4,384)
======= ======= =======
The significant components, which give rise to the Company's deferred tax
assets (liabilities), are as follows:
DECEMBER 31,
-----------------
1999 1998
------- -------
(IN THOUSANDS)
Net operating loss carryforward............................. $25,607 $10,950
Gas and oil acquisition, exploration and development costs
deducted for tax purposes under (over) book............... (3,662) 6,254
Advances from gas purchasers................................ -- 8,585
AMT Credit Carryforwards.................................... 4,499 4,119
Investment tax credit carryforward.......................... 195 857
Option plan compensation.................................... 1,559 1,559
Other....................................................... 2,380 2,265
------- -------
Net deferred tax asset...................................... 30,578 34,589
Valuation allowance......................................... (1,953) (2,575)
------- -------
Recognized net deferred tax asset........................... $28,625 $32,014
======= =======
Net deferred tax assets are comprised of the following:
DECEMBER 31,
-----------------
1999 1998
------- -------
(IN THOUSANDS)
Current..................................................... $ -- $ 8,585
Long-term................................................... 28,625 23,429
------- -------
$28,625 $32,014
======= =======
A valuation allowance of approximately $2.0 million and $2.6 million at
December 31, 1999 and 1998, 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
35
36
TOM BROWN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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, 1999, the Company had investment tax credit carryforwards
of approximately $0.2 million and a net operating loss carryforward of
approximately $73.2 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, $2.3 million in 2004 and $41.9 million in 2019. The Company believes it
will generate sufficient taxable income in 2000 to utilize the benefit of the
$17.6 million net carryforward that will expire at the end of 2000, and, if not,
will enact such other tax planning strategies necessary to utilize such benefit.
Additionally, the Company has approximately $6.2 million of statutory depletion
carryforwards and $4.5 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 were classified as advances on the balance sheet and
were reduced as gas was delivered to the purchasers under the terms of the
contracts. Gas volumes delivered to the purchaser were 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 was 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 were
55,000,000 authorized shares of Common Stock at December 31, 1999, of which
35,308,489 shares and 29,259,989 shares were outstanding at December 31, 1999
and 1998, respectively.
In July 1999, the Company issued 5.8 million shares of common stock to
Unocal as partial consideration in connection with the Unocal Acquisition (see
Note 3).
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 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
36
37
TOM BROWN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 the Company issued
1,000,000 shares of its $1.75 Convertible Preferred Stock, Series A (the
"Preferred Stock") to the seller. There are 2,500,000 shares of Preferred Stock
authorized.
The holder of the Preferred Stock 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 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, 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 gains 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
37
38
TOM BROWN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
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
The Company's 1989 Stock Option Plan expired in December 1999. Options to
purchase 163,000 shares of the Company's common stock, which would have expired
in December 1999, were exercised in 1999 at an average price of $4.76. As of
December 31, 1999, options to purchase 1,550,000 shares of the Company's common
stock were outstanding under the 1989 Plan.
38
39
TOM BROWN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 November
1999, the aggregate number of shares of Common Stock that may be issued under
the 1993 Plan was increased from 2,700,000 shares to 3,200,000 shares. The
exercise price, vesting and duration of the options may vary and will be
determined at the time of issuance.
1999 Plan
The 1999 Long Term Incentive Plan (the "1999 Plan") was adopted by the
Board of Directors on February 17, 1999, and approved by the shareholders on May
20, 1999. The 1999 Plan provides for the grant of stock options, restricted
stock awards, performance awards and incentive awards. There were no grants made
in 1999 under the 1999 Plan. The aggregate number of shares of common stock,
which may be issued under the 1999 Plan, may not exceed 2,000,000 shares. The
maximum value of any performance award granted to any one individual during any
calendar year may not exceed $500,000. The exercise price, vesting and duration
of any grants may vary and will be determined at the time of issuance.
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,
---------------------------------------------------
1999 1998 1997
--------------- --------------- ---------------
WTD. WTD. WTD.
SHARES AVG. SHARES AVG. SHARES AVG.
UNDER EXER. UNDER EXER. UNDER EXER.
OPTION PRICE OPTION PRICE OPTION PRICE
------ ------ ------ ------ ------ ------
(SHARES IN THOUSANDS)
Outstanding, beginning of year.............. 3,402 $13.22 2,173 $12.84 2,110 $11.06
Granted..................................... 1,178 13.91 2,127 16.04 307 19.12
Exercised................................... (248) 6.98 (50) 11.80 (244) 5.54
Cancellations............................... (193) 13.56 (848) 19.43 -- --
----- ----- -----
Outstanding, end of year.................... 4,139 13.77 3,402 13.22 2,173 12.84
===== ===== =====
Exercisable, end of year.................... 2,226 13.10 1,919 11.64 1,501 10.77
===== ===== =====
Available for grant, end of year............ 2,392 945 741
===== ===== =====
The weighted average fair value of options granted during the years ended
December 31, 1999, 1998, and 1997 was $9.72, $9.01, and $10.35, respectively.
The following table summarizes information about stock options outstanding
at December 31, 1999:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------- ------------------------
NO. OF SHS. WTD. AVG. NO. OF SHS.
UNDER REMAINING WTD. AVG. UNDER WTD. AVG.
RANGE OF OUTSTANDING CONTRACTUAL EXERCISE EXERCISABLE EXERCISE
EXERCISE PRICES OPTIONS LIFE PRICE OPTIONS PRICE
- --------------- ----------- ----------- --------- ------------ ---------
(SHARES IN THOUSANDS)
$ 3.81 to 13.00........................ 918 5.24 $ 9.36 774 $ 8.83
$13.32 to 15.25........................ 1,608 6.87 14.28 666 15.00
$15.69 to 18.38........................ 1,613 8.08 15.76 786 15.68
----- -----
4,139 6.98 13.77 2,226 13.10
===== =====
39
40
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 (loss) and net income
(loss) per common share would approximate the following pro forma amounts:
YEARS ENDED DECEMBER 31,
--------------------------
1999 1998 1997
------ -------- ------
(IN THOUSANDS,
EXCEPT PER SHARE AMOUNTS)
Net Income (loss)
As Reported............................................... $5,007 $(45,233) $6,860
Pro Forma................................................. 451 (48,645) 4,708
Basic Net Income (loss) per Common Share:
As Reported............................................... $ .16 $ (1.55) $ 0.27
Pro Forma................................................. $ .01 $ (1.66) $ 0.19
Diluted Net Income (loss) per Common Share:
As Reported............................................... $ .15 $ (1.55) $ 0.26
Pro Forma................................................. $ .01 $ (1.66) $ 0.18
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 1999, 1998, and 1997, respectively: (i) risk-free
interest rates of 6.20, 5.54, and 6.20 percent; (ii) expected lives of 7.0, 7.3
and 7.3 years, (iii) expected volatility of 47.6, 44.3, and 40.9 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, 1999, 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, 1999, 1998 and 1997, was approximately $422,000, $329,000 and $266,000,
respectively. The Company contributed an additional $100,000 to the KSOP for
1997.
40
41
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.
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. The swap contracts
were completely settled as of December 31, 1999.
(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 serves as an officer. The
amounts paid to each of these firms for the years ended December 31, 1999, 1998
and 1997, were approximately $97,000 and $91,000; $100,000 and $35,000; and
$189,000 and $110,000, respectively. The Company also paid approximately
$38,000, $35,000 and $32,000 during the years ended December 31, 1999, 1998 and
1997, 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,
1999, 1998, and 1997, the Company billed $579,000, $508,000 and $960,000,
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 have made available
to each other certain personnel, office services and records with each party
being reimbursed for costs and expenses incurred in connection therewith. During
the years ended December 31, 1999, 1998 and 1997, the Company charged the former
subsidiary approximately $67,000, $86,000 and $80,000, respectively, for such
services. The former subsidiary performs drilling services on certain wells
operated by the Company and charged approximately $1,860,000, $1,643,000, and
$11,000 for such services during the years ended December 31, 1999, 1998 and
1997, 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 12%, 24% and 28% of gas and
oil sales and marketing, gathering and processing revenues for the years ended
December 31, 1999, 1998 and 1997, respectively. Because there are numerous other
parties available to purchase the Company's production, the Company believes the
loss of this purchaser would not materially affect its ability to sell natural
gas or crude oil.
41
42
TOM BROWN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Concentration of Credit Risk
The Company's revenues are derived principally from uncollateralized sales
to customers in the gas and oil 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 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 Paradox Basin of Utah and 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 Retex and 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.
The following tables present information related to the Company's
reportable segments:
DECEMBER 31, 1999
----------------------------------------------
GAS & OIL MARKETING,
EXPLORATION GATHERING
& & TOTAL
DEVELOPMENT PROCESSING DRILLING SEGMENTS
----------- ---------- -------- --------
Revenues from external purchasers.................. $ 85,138 $116,687 $5,643 $207,468
Intersegment revenues.............................. 21,365 -- 4,348 25,713
Depreciation, depletion and amortization........... 40,532 3,107 1,324 44,963
Segment profit..................................... 15,976 1,026 149 17,151
Assets............................................. 467,561 90,262 9,333 567,156
Capital and exploration expenditures............... 120,146 4,080 1,416 125,642
42
43
TOM BROWN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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
The following tables reconcile segment information to consolidated totals:
DECEMBER 31,
------------------------------
1999 1998 1997
-------- -------- --------
Revenues
Revenue from external purchasers.......................... $207,468 $122,857 $118,025
Intersegment revenues..................................... 25,713 20,523 15,182
Intercompany eliminations................................. (18,331) (12,050) (6,832)
-------- -------- --------
Total consolidated revenues....................... $214,850 $131,330 $126,375
======== ======== ========
Profit or (loss)
Total reportable segment profit/loss...................... $ 17,151 $(66,514) $ 18,914
Interest expense.......................................... (5,560) (4,301) (5,920)
Eliminations and other.................................... (541) (546) --
-------- -------- --------
Income (loss) before income taxes......................... $ 11,050 $(71,361) $ 12,994
======== ======== ========
Depreciation, depletion and amortization
Total reportable segment depreciation, depletion and
amortization........................................... $ 44,963 $ 45,253 $ 36,230
Eliminations and other.................................... (748) (678) --
-------- -------- --------
$ 44,215 $ 44,575 $ 36,230
======== ======== ========
Assets
Total reportable segment assets........................... $567,156 $444,226 $452,390
Eliminations and other.................................... (30,857) (2,344) (1,464)
-------- -------- --------
$536,299 $441,882 $450,926
======== ======== ========
43
44
TOM BROWN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(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, 1999, the Company had long-term leases covering certain of
its facilities and equipment. 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)
2000.................................................... $1,233
2001.................................................... 1,220
2002.................................................... 1,192
2003.................................................... 1,080
2004.................................................... 71
Thereafter.............................................. --
------
$4,796
======
Total rental expense incurred for the years ended December 31, 1999, 1998
and 1997, was approximately $1,139,000, $1,043,000, and $741,000, respectively,
all of which represented minimum rentals under non-cancelable operating leases.
Firm Transportation Commitments
As of December 31, 1999, 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 to increase the rate from approximately $.45
per Mcf to $.76 per Mcf. Wildhorse began paying the higher rate of $.76 per Mcf
in August 1998. In August 1999 Wildhorse learned that it was likely that the
rate increase would be limited to $.62 per Mcf. As such, Wildhorse recorded a
receivable of approximately $2.3 million (approximately $1.0 million net to the
Company) representing estimated recoupment of overpayments made at the higher
rate of $.76 per Mcf. In September 1999 the rate on this pipeline was further
reduced to $.47.
On September 1, 1999, the Company took assignment of firm transportation
commitments within Wildhorse based upon its 45% interest in Wildhorse.
44
45
TOM BROWN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Based upon current rates, 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)
2000.................................................... $ 3,997
2001.................................................... 3,997
2002.................................................... 3,257
2003.................................................... 2,641
2004.................................................... 2,208
Thereafter.............................................. 2,438
-------
$18,538
=======
Environmental Matters
Rocno Corporation, a wholly-owned subsidiary of the Company, is a party to
a trust agreement in connection with the environmental clean-up plan for the
Sheridan Superfund Site in Waller County, Texas. Rocno's share of the estimated
cleanup costs was accrued in the consolidated financial statements at December
31, 1999. 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, 1999
Revenues................................... $31,513 $36,398 $57,121 $ 89,818 $214,850
Gross profit(1)............................ 12,394 15,022 23,854 30,110 $ 81,380
Net income (loss) attributable to common
stock.................................... (2,971) (996) 3,161 5,813 $ 5,007
Net income (loss) per common share(2)
Basic.................................... (.10) (.03) .09 .17 $ .16
Diluted.................................. (.10) (.03) .09 .16 $ .15
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)
- ---------------
(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 and cost of gas sold.
(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.
45
46
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,
--------------------------------
1999 1998 1997
--------- -------- ---------
(IN THOUSANDS)
Capitalized costs
Proved gas and oil properties...................... $ 427,676 $344,766 $ 456,093
Unproved gas and oil properties.................... 42,785 42,570 44,468
--------- -------- ---------
Total gas and oil properties....................... 470,461 387,336 500,561
Less: Accumulated depreciation, depletion and
amortization.................................. (116,403) (78,161) (151,544)
--------- -------- ---------
Net capitalized costs.............................. $ 354,058 $309,175 $ 349,017
========= ======== =========
YEARS ENDED DECEMBER 31,
----------------------------
1999 1998 1997
-------- ------- -------
(IN THOUSANDS)
Costs incurred
Proved property acquisition costs(1)................... $ 65,753 $ -- $35,540
Unproved property acquisition costs.................... 6,945 3,283 6,128
Exploration costs...................................... 12,016 22,844 16,036
Development costs...................................... 33,232 49,262 33,731
-------- ------- -------
Total........................................ $117,946 $75,389 $91,435
======== ======= =======
- ---------------
(1) For 1999 proved property acquisition costs includes $19.9 million for a gas
processing plant in connection with the Unocal Acquisition (see Note 3).
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, 1999,
1998 and 1997, 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.
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.
46
47
TOM BROWN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
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(1)
(MMCF) (MBLS)
-------- -------
Proved reserves:
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
Revisions of previous estimates........................... (8,571) 1,505
Purchases of minerals in place............................ 65,982 6,989
Extensions and discoveries................................ 58,032 292
Sales of minerals in place................................ (1,018) (22)
Production................................................ (40,514) (1,445)
------- ------
Estimated reserves at December 31, 1999..................... 445,933 13,001
======= ======
Proved developed reserves:
December 31, 1996......................................... 257,241 8,994
December 31, 1997......................................... 258,756 5,749
December 31, 1998......................................... 263,747 4,029
December 31, 1999......................................... 333,858 11,398
- ---------------
(1) Oil volumes include natural gas liquids which are insignificant for all
years shown except 1999. For 1999, purchases of minerals in place and
production include 6.0 million and 0.5 million barrels of natural gas
liquids. Proved developed reserves at December 31, 1999 include 6.0 million
barrels of natural gas liquids related to the 1999 Unocal Acquisition.
47
48
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,
----------------------------------
1999 1998 1997
---------- --------- ---------
(IN THOUSANDS)
Future cash flows......................................... $1,107,515 $ 764,974 $ 805,645
Future production costs................................... (320,397) (217,632) (225,488)
Future development costs.................................. (85,712) (74,371) (50,839)
---------- --------- ---------
Future net cash flows before tax.......................... 701,406 472,971 529,318
Future income taxes....................................... (119,950) (71,960) (77,277)
---------- --------- ---------
Future net cash flows after tax........................... 581,456 401,011 452,041
Annual discount at 10%.................................... (247,897) (179,294) (186,867)
---------- --------- ---------
Standardized measure of discounted future net cash
flows................................................... $ 333,559 $ 221,717 $ 265,174
========== ========= =========
Discounted future net cash flows before income taxes...... $ 393,423 $ 254,020 $ 300,814
========== ========= =========
Natural gas and oil prices have increased since December 31, 1999.
Accordingly, the discounted future net cash flows shown above could be different
if the standardized measure were calculated using current prices.
Changes in Standardized Measure of Discounted Future Net Cash Flows
(Unaudited)
YEARS ENDED DECEMBER 31,
-------------------------------
1999 1998 1997
-------- -------- ---------
(IN THOUSANDS)
Gas and oil sales, net of production costs.................. $(76,052) $(56,032) $ (68,446)
Net changes in anticipated prices and production cost....... 32,745 (36,581) (267,369)
Extensions and discoveries, less related costs.............. 31,796 33,651 28,816
Changes in estimated future development costs............... 21,246 (2,652) 21,347
Previously estimated development costs incurred............. 1,435 8,690 315
Net change in income taxes.................................. (27,561) 3,336 106,893
Purchase of minerals in place............................... 98,419 -- 16,059
Sales of minerals in place.................................. (1,207) (151) (11,534)
Accretion of discount....................................... 25,402 30,081 60,875
Revision of quantity estimates.............................. 369 (10,716) (49,263)
Changes in production rates and other....................... 5,250 (13,083) (38,732)
-------- -------- ---------
Change in Standardized Measure.............................. $111,842 $(43,457) $(201,039)
======== ======== =========
48
49
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
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.
49
50
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 -- Purchase and Sale Agreement, dated June 8, 1999, between
Union Oil Company of California and the Registrant
(Incorporated by reference to Exhibit 10.1 in the
Registrant's Form 8-K Report dated July 19, 1999 and
filed with the Securities and Exchange Commission on July
19, 1999)
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 15, 1996)
3.2* -- Certificate of Amendment, dated May 25, 1999, to
Certificate of Incorporation of Registrant
3.3 -- 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)
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 -- 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)
10.2 -- 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)
10.3 -- Stock Ownership and Registration Rights Agreement dated
June 29, 1999 between Union Oil Company of California and
the Registrant (Incorporated by reference to Exhibit 10.2
in the Registrant's Form 8-K Report dated July 19, 1999,
and filed with the Securities and Exchange Commission on
July 19, 1999)
10.4 -- 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 for the
quarterly period ended March 31, 1998, and filed with the
Securities and Exchange Commission on May 14, 1998)
10.5 -- 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 for the quarterly period ended September 30, 1998,
and filed with the Securities and Exchange Commission on
November 13, 1998)
50
51
10.6 -- Second Amendment and Waiver, dated March 15, 1999, to the Credit Agreement, dated April
17, 1998 (Incorporated by reference to Exhibit 10.7 in the Registrant's Form 10-K
Report for the fiscal year ended December 31, 1998, and filed with the Securities and
Exchange Commission on March 19, 1999)
10.7 -- Third Amendment dated June 25, 1999 to the Credit Agreement dated April 17, 1998
(Incorporated by reference to Exhibit 10.1 in the Registrant's Form 10-Q Report for the
quarterly period ended June 30, 1999, and filed with the Securities and Exchange
Commission on August 13, 1999)
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 for the fiscal year ended December 31, 1998, and filed
with the Securities and Exchange Commission on March 19, 1999)
Executive Compensation Plans and Arrangements (Exhibits 10.9 through 10.15):
10.9 -- 1989 Stock Option Plan (Incorporated by reference to Exhibit 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 -- Amended and Restated 1993 Stock Option Plan (Incorporated by reference to Exhibit 10.4
in the Registrant's Form 10-Q Report for the quarterly period ended June 30, 1999, and
filed with the Securities and Exchange Commission on August 13, 1999)
10.11* -- 1999 Long Term Incentive Plan effective as of February 17, 1999.
10.12 -- Tom Brown, Inc. KSOP Plan (Incorporated by reference to Exhibit 10.19 in the
Registrant's Form 10-K Report for the fiscal year ended December 31, 1996, and filed
with the Securities and Exchange Commission on March 27, 1997)
10.13* -- Tom Brown, Inc. 401(k) Retirement Plan effective as of January 1, 2000.
10.14* -- Sauer Drilling Company Adoption Agreement and Prototype 401(k) Retirement Plan
effective as of January 1, 1999.
10.15 -- Second Amendment and Restated Employment Agreement dated January 1, 1997, between the
Registrant and Donald L. Evans (Incorporated by reference to Exhibit 10.15 in the
Registrant's Form 10-K Report for the fiscal year ended December 31, 1996, and filed
with the Securities and Exchange Commission on March 27, 1997)
10.16 -- 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 for the quarterly period ended June 30, 1998, and filed
with the Securities and Exchange Commission on August 10, 1998)
10.17 -- Employment Agreement dated May 3, 1999 between the Registrant and James D. Lightner
(Incorporated by reference to Exhibit 10.3 in the Registrant's Form 8-K Report dated
July 19, 1999, and filed with the Securities and Exchange Commission on July 19, 1999)
10.18 -- 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 for the
quarterly period ended June 30, 1998, and filed with the Securities and Exchange
Commission on August 12, 1998)
51
52
10.19* -- Amended Schedule to Severance Agreement filed as Exhibit No. 10.1 to the
Registrant's Form 10-Q Report for the quarterly period ended June 30, 1998, and
filed with the Securities and Exchange Commission on August 12, 1998 identifying
officers and executives of the Registrant who are parties thereto and the multiple of
earnings payable to each officer or executive upon termination resulting from certain
change in control events
10.20 -- 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 for the quarterly
period ended June 30, 1998, and filed with the Securities and Exchange Commission
on August 12, 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
(4) Reports on Form 8-K:
None
52
53
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
-----------------------------------
Donald L. Evans
Chairman of the Board of Directors
and Chief Executive Officer
Date: March 17, 2000
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 Chief March 17, 2000
- ----------------------------------------------------- Executive Officer
Donald L. Evans
/s/ JAMES D. LIGHTNER President and Director March 17, 2000
- -----------------------------------------------------
James D. Lightner
/s/ DANIEL G. BLANCHARD Vice President and Chief Financial March 17, 2000
- ----------------------------------------------------- Officer
Daniel G. Blanchard
/s/ R. KIM HARRIS Vice President -- Finance and March 17, 2000
- ----------------------------------------------------- Controller
R. Kim Harris
/s/ THOMAS C. BROWN Director March 17, 2000
- -----------------------------------------------------
Thomas C. Brown
/s/ DAVID M. CARMICHAEL Director March 17, 2000
- -----------------------------------------------------
David M. Carmichael
/s/ HENRY GROPPE Director March 17, 2000
- -----------------------------------------------------
Henry Groppe
/s/ EDWARD W. LEBARON, JR. Director March 17, 2000
- -----------------------------------------------------
Edward W. LeBaron, Jr.
/s/ JAMES B. WALLACE Director March 17, 2000
- -----------------------------------------------------
James B. Wallace
/s/ ROBERT H. WHILDEN, JR. Director March 17, 2000
- -----------------------------------------------------
Robert H. Whilden, Jr.
53
54
TOM BROWN, INC.
EXHIBITS
TO
ANNUAL REPORT ON FORM 10-K
FOR THE PERIOD ENDED
DECEMBER 31, 1999
55
INDEX TO EXHIBITS
EXHIBIT NO. DESCRIPTION
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2.1 -- Purchase and Sale Agreement, dated June 8, 1999, between
Union Oil Company of California and the Registrant
(Incorporated by reference to Exhibit 10.1 in the
Registrant's Form 8-K Report dated July 19, 1999 and
filed with the Securities and Exchange Commission on July
19, 1999)
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 15, 1996)
3.2* -- Certificate of Amendment, dated May 25, 1999, to
Certificate of Incorporation of Registrant
3.3 -- 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)
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 -- 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)
10.2 -- 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)
10.3 -- Stock Ownership and Registration Rights Agreement dated
June 29, 1999 between Union Oil Company of California and
the Registrant (Incorporated by reference to Exhibit 10.2
in the Registrant's Form 8-K Report dated July 19, 1999,
and filed with the Securities and Exchange Commission on
July 19, 1999)
10.4 -- 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 for the
quarterly period ended March 31, 1998, and filed with the
Securities and Exchange Commission on May 14, 1998)
10.5 -- 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 for the quarterly period ended September 30, 1998,
and filed with the Securities and Exchange Commission on
November 13, 1998)
10.6 -- Second Amendment and Waiver, dated March 15, 1999, to the
Credit Agreement, dated April 17, 1998 (Incorporated by
reference to Exhibit 10.7 in the Registrant's Form 10-K
Report for the fiscal year ended December 31, 1998, and
filed with the Securities and Exchange Commission on
March 19, 1999)
56
EXHIBIT NO. DESCRIPTION
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10.7 -- Third Amendment dated June 25, 1999 to the Credit
Agreement dated April 17, 1998 (Incorporated by reference
to Exhibit 10.1 in the Registrant's Form 10-Q Report for
the quarterly period ended June 30, 1999, and filed with
the Securities and Exchange Commission on August 13,
1999)
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 for the fiscal year ended
December 31, 1998, and filed with the Securities and
Exchange Commission on March 19, 1999)
Executive Compensation Plans and Arrangements (Exhibits 10.9
through 10.15):
10.9 -- 1989 Stock Option Plan (Incorporated by reference to
Exhibit 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 -- Amended and Restated 1993 Stock Option Plan (Incorporated
by reference to Exhibit 10.4 in the Registrant's Form
10-Q Report for the quarterly period ended June 30, 1999,
and filed with the Securities and Exchange Commission on
August 13, 1999)
10.11* -- 1999 Long Term Incentive Plan effective as of February
17, 1999.
10.12 -- Tom Brown, Inc. KSOP Plan (Incorporated by reference to
Exhibit 10.19 in the Registrant's Form 10-K Report for
the fiscal year ended December 31, 1996, and filed with
the Securities and Exchange Commission on March 27, 1997)
10.13* -- Tom Brown, Inc. 401(k) Retirement Plan effective as of
January 1, 2000.
10.14* -- Sauer Drilling Company Adoption Agreement and Prototype
401(k) Retirement Plan effective as of January 1, 1999.
10.15 -- Second Amendment and Restated Employment Agreement dated
January 1, 1997, between the Registrant and Donald L.
Evans (Incorporated by reference to Exhibit 10.15 in the
Registrant's Form 10-K Report for the fiscal year ended
December 31, 1996, and filed with the Securities and
Exchange Commission on March 27, 1997)
10.16 -- 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 for the quarterly period
ended June 30, 1998, and filed with the Securities and
Exchange Commission on August 10, 1998)
10.17 -- Employment Agreement dated May 3, 1999 between the
Registrant and James D. Lightner (Incorporated by
reference to Exhibit 10.3 in the Registrant's Form 8-K
Report dated July 19, 1999, and filed with the Securities
and Exchange Commission on July 19, 1999)
10.18 -- 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 for the quarterly period ended June 30, 1998, and
filed with the Securities and Exchange Commission on
August 12, 1998)
57
EXHIBIT NO. DESCRIPTION
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10.19* -- Amended Schedule to Severance Agreement filed as Exhibit
No. 10.1 to the Registrant's Form 10-Q Report for the
quarterly period ended June 30, 1998, and filed with the
Securities and Exchange Commission on August 12, 1998
identifying officers and executives of the Registrant who
are parties thereto and the multiple of earnings payable
to each officer or executive upon termination resulting
from certain change in control events
10.20 -- 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 for the quarterly period
ended June 30, 1998, and filed with the Securities and
Exchange Commission on August 12, 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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* Filed herewith