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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, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 0-3880
TOM BROWN, INC.
(Exact name of registrant as specified in its charter)
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DELAWARE 95-1949781
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation 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
riling requirements for the past 90 days. Yes [ ] 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 [ ]
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The aggregate market value of the Registrant's Common Stock held by
non-affiliates (based upon the last sale price of $35.25 per share as quoted on
the NASDQ National Market System) on March 8, 2001 was approximately
$1,364,101,962.
As of March 8, 2001, there were 38,697,928 shares of Common Stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's definitive proxy statement for the 2001 Annual
Meeting of Stockholders to be held on May 10, 2001 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....................................... 12
Item 6. Selected Financial Data..................................... 13
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 15
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk...................................................... 19
Item 8. Financial Statements and Supplementary Data................. 21
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 46
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 46
Item 11. Executive Compensation...................................... 46
Item 12. Security Ownership of Certain Beneficial Owners and
Management................................................ 46
Item 13. Certain Relationships and Related Transactions.............. 46
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K....................................................... 47
Signatures.................................................. 50
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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 exploration for, and the
acquisition, development, production, marketing, and sale of, natural gas,
natural gas liquids and crude oil in North America. 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.
In December 2000, the Company initiated a cash tender for all the
outstanding stock of Stellarton Energy Corporation. This transaction was
completed on January 12, 2001. With this acquisition, the Company expanded its
exploration and development activities to now include the western Alberta area
in Canada.
The Company's industry segments are (i) the exploration for, and the
acquisition, development and production of, natural gas, natural gas liquids 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 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 expansion
into Canada is an extension of this fundamental strategy.
The Company's year-end acreage position was approximately 3,092,000 gross
(2,033,000 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
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operations for the further development and expansion of these areas.
Approximately 86% of the net acreage is undeveloped.
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 2000 over 1999 by 15% due primarily
to continued drilling success in its core areas. Year-end proved reserves were
603 billion cubic feet equivalent ("Bcfe"), compared to year-end 1999 reserves
of 524 Bcfe. Since December 31, 1995, the Company has increased proved reserves
at a compounded annual growth rate of 21%, or from 188 Bcfe to 603 Bcfe.
Reserve replacement for 2000 was 226% from all sources and 180% from
additions and revisions only. Finding cost was $0.89 per Mcfe for the year from
all sources. The Company's reserve to production ratio decreased to 9.7 years at
year-end 2000 from 10.6 years at year-end 1999. In addition to increasing
reserves, the Company also increased its production 27% from 49.2 Bcfe in 1999
to 62.3 Bcfe in 2000.
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") conducted gas gathering and
processing activities in the Rocky Mountains. Wildhorse is owned 55% by Kinder
Morgan, Inc. ("KM") and 45% by the Company. In November 2000, the gathering and
processing assets were distributed to the Company in anticipation of the
dissolution of Wildhorse. KM received the storage facility and a cash payment.
TBI Field Services, Inc. ("TBIFS") was formed as a wholly-owned subsidiary of
Tom Brown, Inc. to administer the gathering and processing assets received in
this distribution.
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 75% of the Company's proved reserves at December 31, 2000.
The Company owns interests in 1,129 producing wells in these basins that
averaged net daily production of 120 Mmcfe for 2000. The Company has
approximately 2,056,000 gross (1,585,000 net) developed and undeveloped acres in
these basins, including option acreage of approximately 716,000 gross
undeveloped acres in the Wind River Basin.
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.
Permian and Val Verde Basins
The Permian and Val Verde Basins accounted for approximately 11% of the
Company's proved reserves at December 31, 2000. The Company's share of
production from these basins averaged 30 Mmcfepd of natural gas for 2000. The
Company holds
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between 30% to 50% working interests in approximately 25,000 gross acres and 68
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 375 wells and has approximately 78,000 net developed
and undeveloped acres in this basin.
In the Permian Basin, the Company also assembled an acreage position of
approximately 24,000 net acres to test the Montoya formation at a vertical depth
of approximately 15,500 feet. The first test well for this play is expected to
reach total depth early in the second quarter of 2001.
East Texas Basin
Together with Marathon Oil Corporation, the Company participated in a six
well developmental drilling program in the Mimms Creek Field in Freestone
County, Texas following 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 34,000 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 STELLARTON ENERGY CORPORATION
Effective January 16, 2001, the Company purchased 100% of Stellarton Energy
Corporation ("Stellarton"), in a transaction valued at $94.8 million, which will
be funded through a five-year Canadian term loan. Stellarton's assets are
located in Western Alberta, Canada with estimated total net proved reserves
(after royalty) of 58.6 billion cubic feet (Bcf) of gas and 2.82 million barrels
of oil and natural gas liquids for total equivalent proved reserves of 75.5
Bcfe.
ACQUISITION OF ROCKY MOUNTAIN ASSETS
In June 2000, the Company purchased an additional working interest in the
Company operated Pavillion Field in the Wind River Basin in Wyoming. The
acquired interests included an estimated 24 Bcfe of proved reserves purchased
for total consideration of $15.2 million net of normal closing adjustments.
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 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
compliment the Company's 163,000 net undeveloped acres in the Paradox Basin.
Included in the acquisition was 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 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.
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
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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. 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. In
November 2000, the Wildhorse gathering and processing assets were distributed to
the Company in anticipation of the dissolution of Wildhorse. KM received the
Wildhorse storage facility and a cash payment. TBI Field Services, Inc. was
formed as a wholly-owned subsidiary of Tom Brown, Inc. to administer the
gathering and processing assets received in this distribution.
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 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. The assets included five drilling rigs, tubular goods, a yard and
related assets. In 1999 and 2000, Sauer acquired two additional drilling rigs
for approximately $1.5 million in total.
MARKETS
The Company's gas production has historically been sold under
month-to-month contracts with marketing companies. During 2000, 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 $6.02 per million British thermal unit ("Mmbtu") for
December 2000 to a low of $2.34 per Mmbtu for January 2000. Additionally, the
Company produced approximately 71% of its gas production for 2000 from the Rocky
Mountain area where the price of gas varied as compared to NYMEX prices from
$.07 per Mmbtu below NYMEX prices in December 2000 to $1.26 below NYMEX prices
in September 2000.
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, natural gas liquids and crude oil for each
of the years ended December 31, 2000, 1999 and 1998.
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YEARS ENDED DECEMBER 31,
-----------------------------------
2000 1999 1998
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Production Volumes:
Natural Gas (MMcf) ..................... 51,199 40,514 35,887
Crude Oil (MBbls)(1) ................... 1,847 1,445 1,027
Net Average Daily Production Volumes:
Natural Gas (Mcf) ...................... 139,888 110,997 98,321
Crude Oil (Bbls)(1) .................... 5,046 3,956 2,814
Average Sales Prices:
Natural Gas (per Mcf) .................. $ 3.46 $ 2.04 $ 1.85
Crude Oil (per Bbl)(1) ................. $ 21.49 $ 15.20 $ 11.37
Average Production Cost (per Mcfe)(2) .... $ .76 $ .58 $ .52
- ----------
(1) Oil volumes include natural gas liquids, which were 1,074,000 barrels for
2000, compared to 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.)
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
On January 19, 2001, Donald L. Evans, the Company's Chairman of the Board
and Chief Executive Officer resigned to accept an appointment as the Secretary
of the U.S. Department of Commerce. The Company's Board of Directors elected
James B. Wallace as the new Chairman of the Board and James D. Lightner to the
additional position of Chief Executive Officer.
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The executive officers of the Company on March 8, 2001 were as follows:
NAME AGE POSITION WITH COMPANY SINCE
- ---- --- --------------------- -----
James B. Wallace..................... 71 Chairman of the Board 2001
James D. Lightner.................... 48 President, Chief Executive Officer 1999
and Director
Thomas W. Dyk........................ 47 Executive Vice President and Chief 1998
Operating Officer
Peter R. Scherer..................... 44 Executive Vice President 1986
Daniel G. Blanchard.................. 40 Executive Vice President, Chief 1999
Financial Officer and Treasurer
Hilary G. Dussing.................... 43 Vice President -- Exploration 1999
Rodney G. Mellott.................... 43 Vice President -- Land and Business 1999
Development
Bruce R. DeBoer...................... 48 Vice President, General Counsel and 1997
Secretary
Doug R. Harris...................... 46 Vice President - Operations 2001
Each executive officer is elected annually by the Company's Board of
Directors to serve at the Board's discretion.
EMPLOYEES
At December 31, 2000, the Company had 448 employees of which 199 were
employed by Sauer. None of the Company's employees are represented by labor
unions or covered by any collective bargaining agreement. The Company considers
its relations with its employees to be satisfactory.
REGULATION
Regulation of Gas and Oil Production
Gas and oil operations are subject to various types of regulation by state
and federal agencies. Legislation affecting the gas and oil industry is under
constant review for amendment or expansion. Also, numerous departments and
agencies, both federal and state, are authorized by statute to issue rules and
regulations binding on the gas and oil industry and its individual members, some
of which carry substantial penalties for failure to comply. The regulatory
burden on the gas and oil industry increases the Company's cost of doing
business and, consequently, affects its profitability.
Gas Price Controls
Prior to January 1993, certain natural gas sold by the Company was subject
to regulation by the Federal Energy Regulatory Commission ("FERC") under the
Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 ("NGPA"). The
NGPA prescribed maximum lawful prices for natural gas sales effective December
1, 1978. Effective January 1, 1993, natural gas prices were completely
deregulated and sales of the Company's natural gas are now made at market
prices. The majority of the Company's gas sales contracts either contain
decontrolled price provisions or already provide for market prices.
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.
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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 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. In
December of 2000 the Company added to its Tribal base inventory around the
Pavillion Field by signing ten additional ten-year leases covering nearly 25,800
net acres. The Company is currently awaiting final approval of the leases by the
Bureau of Indian Affairs.
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.
The oil and gas 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, 2000.
Excluded from the table are approximately 716,000 gross (585,000 net) acres in
Wyoming under gas and oil option agreements acquired from certain Indian tribes.
DEVELOPED UNDEVELOPED
----------------- ---------------------
GROSS NET GROSS NET
------- ------- --------- ---------
Colorado.................................... 101,519 82,350 538,594 424,298
Kansas...................................... 1,961 1,563 1,802 1,614
Louisiana................................... 11,551 4,000 7,425 1,753
Michigan.................................... -- -- 303 121
Mississippi................................. 596 313 1,907 270
Montana..................................... 4,678 718 158,307 26,443
Nebraska.................................... -- -- 32,895 32,146
New Mexico.................................. 15,737 3,961 2,440 2,096
North Dakota................................ 3,880 115 6,280 212
Oklahoma.................................... 34,125 11,368 6,803 2,789
Texas....................................... 108,813 38,706 125,292 74,466
Utah........................................ 6,162 5,519 57,272 52,222
West Virginia............................... 3,731 1,135 155,616 80,309
Wyoming..................................... 132,852 61,664 854,544 537,498
Other....................................... 360 58 10 2
------- ------- --------- ---------
Total............................. 425,965 211,470 1,949,490 1,236,239
======= ======= ========= =========
"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 at December 31, 2000,
including future net revenues and the present value of future net cash flows,
were prepared by the Company's petroleum engineering staff and audited by Ryder
Scott (independent petroleum consultants). The reserve estimates were prepared
by Ryder Scott at December 31, 1999 and 1998. Guidelines established by the
Securities and Exchange Commission (the "SEC") were utilized to prepare these
reserve estimates. 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 15 of
the Notes to Consolidated Financial Statements included herein.
The Company has no gas and oil reserves or production subject to long-term
supply or similar agreements with foreign governments or authorities.
Estimates of the Company's total proved gas and oil reserves have not been
filed with or included in reports to any federal authority or agency other than
the SEC.
PRODUCTIVE WELLS
The following table sets forth the gross and net productive gas and oil
wells in wells in which the Company owned an interest at December 31, 2000.
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PRODUCTIVE WELLS
-----------------------------
GROSS NET
----------- ---------------
GAS OIL GAS OIL
----- --- ------ ------
Colorado.............................................. 549 3 303.16 2.13
Louisiana............................................. 41 38 11.68 12.36
New Mexico............................................ 28 25 5.22 2.2
North Dakota.......................................... 18 -- 1.25 --
Oklahoma.............................................. 157 28 31.57 7.71
Utah.................................................. 9 17 6.14 16.38
Texas................................................. 138 300 56.16 72.95
West Virginia......................................... 116 -- 38.09 --
Wyoming............................................... 605 271 245.81 57.91
Other................................................. 10 10 3.69 1.51
----- --- ------ ------
Total....................................... 1,671 692 702.77 173.15
===== === ====== ======
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,
-----------------------------------------------------------------------------------------------
2000 1999 1998
----------------------------- ----------------------------- -----------------------------
TYPE OF WELL GROSS NET NET% GROSS NET NET% GROSS NET NET%
------- ------- ------- ------- ------- ------- ------- ------- -------
Exploratory
Gas ..... -- -- -- 2 .8 20 8 3.0 40
Oil ..... -- -- -- -- -- -- -- -- --
Dry ..... 3 2.3 100 4 3.2 80 7 4.5 60
------- ------- ------- ------- ------- ------- ------- ------- -------
3 2.3 100 6 4.0 100 15 7.5 100
Development
Gas ..... 63 33.7 93 37 16.3 99 52 31.4 78
Oil ..... 1 .2 1 1 0.2 1 16 4.2 11
Dry ..... 4 2.3 6 -- -- -- 6 4.2 11
------- ------- ------- ------- ------- ------- ------- ------- -------
68 36.2 100 38 16.5 100 74 39.8 100
Total ..... 71 38.5 44 20.5 89 47.3
======= ======= ======= ======= ======= =======
At December 31, 2000, 25 gross (13.5 net) development wells and 8 gross
(4.5 net) exploration wells were in various stages of drilling and completion in
Texas, Colorado, and Wyoming.
OTHER PROPERTIES
The Company leases its corporate 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.
The Company owns a 3,200 square foot building located on a 2.94 acre tract
in Midland, Texas. The facility is used primarily for storage of pipe and
oilfield equipment.
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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. 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, 2000.
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, 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
March 31, 2000.............................................. 18 3/8 12
June 30, 2000............................................... 23 1/16 17 3/4
September 30, 2000.......................................... 24 1/2 17
December 31, 2000........................................... 36 20 7/16
On March 8,2001 the last sale price of the Company's Common Stock, as
reported by the NASDAQ National Market System, was $35.25 per share.
The transfer agent for the Company's Common Stock is EquiServe Trust
Company, N.A., Canton, Massachusetts.
On December 31, 2000, the outstanding shares of the Company's Common Stock
(38,351,860 shares) were held by approximately 1970 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.
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In January 1996, in connection with the acquisition of KN Production
Company, ("KNPC") the Company issued 1,000,000 shares of its $1.75 Convertible
Preferred Stock, Series A (the "Preferred Stock") to the seller. The Preferred
Stock was 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"). On June 15, 2000, the Company elected
to exchange 1,666,000 shares of its Common Stock for all 1,000,000 outstanding
shares of the Preferred Stock as the Common Stock had traded above the Threshold
Price.
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. As of March 1, 2001, the Board of Directors amended and restated the
Rights Plan. Each Right entitles the registered holder to purchase, for the $120
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 15% or
more of the Company's Common Stock or announces a tender offer which would
result in ownership by a person or group of 15% 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 1, 2011, 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.
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.)
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YEARS ENDED DECEMBER 31,
--------------------------------------------------------------------------------
2000 1999 1998 1997 1996
------------ ------------ ------------ ------------ ------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Revenues(1) ............................... $ 253,910 $ 123,411 $ 89,939 $ 93,175 $ 45,581
============ ============ ============ ============ ============
Net income (loss) attributable to common
stock ................................... 65,703 5,007 (45,233) 6,860 6,263
============ ============ ============ ============ ============
Weighted average number of common shares
outstanding
Basic ................................... 36,664 32,228 29,251 25,110 21,116
============ ============ ============ ============ ============
Diluted ................................. 37,897 32,466 29,251 26,407 22,525
============ ============ ============ ============ ============
Net income (loss) per common share
Basic ................................... 1.79 .16 (1.55) .27 .30
============ ============ ============ ============ ============
Diluted ................................. 1.76 .15 (1.55) .26 .28
============ ============ ============ ============ ============
Total assets .............................. 629,535 536,299 441,882 450,926 406,374
============ ============ ============ ============ ============
Long-term debt, net of current
maturities .............................. 54,000 81,000 55,000 23,000 119,000
============ ============ ============ ============ ============
Other Financial Data:
EBITDAX(2) .............................. 177,643 74,438 49,348 69,716 33,173
Net cash provided by operating
activities before changes in working
capital(2) ........................... 159,956 59,821 34,404 59,652 31,902
Net cash provided by operating
activities ........................... 132,958 38,857 60,100 47,600 29,114
Net cash used in investing
activities ........................... (117,738) (54,999) (89,634) (86,672) (131,434)
Net cash (used in) provided by financing
activities ........................... (10,196) 25,982 25,667 25,105 117,842
(1) Certain reclassifications have been made to amounts reported in previous
years to conform to the 2000 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 excludes $51.3 million
for impairment of gas and oil properties, which were non-cash charges.
The following tables set forth selected information for the Company's gas
and oil sales volumes and proved reserves for each of the years shown.
YEARS ENDED DECEMBER 31,
------------------------------------------------------------------
2000 1999 1998 1997 1996
---------- ---------- ---------- ---------- ----------
Volumes sold:
Gas (Mmcf) .................... 51,199 40,514 35,887 31,842 16,762
Oil (MBbls)(1) ................ 1,847 1,445 1,027 1,159 545
Proved reserves at period end:
Gas (Mmcf) .................... 535,373 445,933 372,022 347,104 359,167
Oil (MBbls)(1) ................ 11,193 13,001 5,682 7,227 12,306
(1) Oil volumes include natural gas liquids ("NGL") for the periods shown. For
2000 and 1999, there were 1,074,000 and 535,000 barrels of NGL production
and 5,077,400 and 6,266,000 barrels of NGL reserves, respectively. NGL
volumes in years prior to 1999 were insignificant.
14
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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 2000 and
1999 due to a mid 1999 acquisition of properties and a cyrogenic natural gas
processing plant from Unocal and due to successful drilling results. Higher
commodity prices and production in 2000 contributed significantly to the
operating results for the period.
Revenues
During 2000, revenues from gas, oil and natural gas liquids production
increased 108% to $217.0 million, as compared to $104.4 million in 1999. Such
increase was the result of an increase in (i) average gas prices received by the
Company from $2.04 per Mcf in 1999 to $3.46 per Mcf in 2000, which increased
revenues $72.7 million, (ii) average oil and natural gas liquids prices received
from $15.20 to $21.49 which increased revenues $11.6 million, (iii) gas sales
volumes increased by 26% to 51.2 Bcf which increased revenues by $21.8 million
(due primarily to the Unocal Acquisition and to successful drilling results),
and (iv) oil and natural gas liquids sales volumes of 28% to 1.8 million
barrels, which increased revenues by $6.5 million due primarily to the impact of
a full year's operations from the Unocal Acquisition.
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 $7.8 million, (ii) average oil and natural gas liquids prices received
from $11.37 to $15.20 which increased revenues $5.5 million, (iii) gas sales
volumes increased by 13% to 40.5 Bcf which increased revenues by $8.6 million
due primarily to the Unocal Acquisition and to successful drilling results, and
(iv) oil and natural gas liquids sales volumes increase by 41% to 1.4 million
barrels, which increased revenues by $4.4 million due primarily to the Unocal
Acquisition.
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,
------------------------------------------
2000 1999 1998
----------- ----------- -----------
(IN THOUSANDS)
Revenues:
Natural gas sales ............................. $ 177,267 $ 82,479 $ 66,392
Crude oil sales(1) ............................ 39,701 21,952 11,680
Gathering and processing ...................... 18,283 11,968 9,061
Marketing and trading, net .................... 5,841 (786) (2,471)
Drilling ...................................... 11,472 5,645 4,561
Interest income and other ..................... 1,346 2,153 716
----------- ----------- -----------
Total revenues ................................ $ 253,910 $ 123,411 $ 89,939
=========== =========== ===========
Net income (loss) attributable to common stock .. $ 65,703 $ 5,007 $ (45,233)
=========== =========== ===========
YEARS ENDED DECEMBER 31,
-----------------------------------------
2000 1999 1998
----------- ----------- -----------
Natural gas production sold (Mmcf) ........... 51,199 40,514 35,887
Crude oil production (Mbbls)(1) .............. 1,847 1,445 1,027
Average natural gas sales price ($/Mcf) ...... $ 3.46 $ 2.04 $ 1.85
Average crude oil sales price ($/Bbl) ........ $ 21.49 $ 15.20 $ 11.37
(1) Crude oil includes natural gas liquids ("NGL") for all years presented. For
2000 and 1999, NGL volumes were 1,074,000 and 535,000 barrels and NGL sales
were $18,015,000 and $6,509,000, respectively, from a mid 1999 property
15
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acquisition from Unocal. For years prior to 1999, NGL volumes and sales
were insignificant.
Gathering and processing revenues in 1998 reflect the Company's 45% share
of such revenues generated by Wildhorse. Effective July 1, 1999, the Company
acquired the Lisbon natural gas processing plant in the Unocal acquisition which
generated incremental processing revenue in the second half of 1999 and all of
2000. Gathering and processing revenues increased by 53% in 2000 as a result of
incremental volumes gathered by Wildhorse primarily from the Wind River Basin
where the Company has a significant production base.
Net marketing and trading income increased from a net loss in 1998 and 1999
to a profitable gross margin of $5.8 million in 2000. This was attributable to
(i) a general increase in the Company's natural gas marketing operations, (ii)
an increase in the volume of gas marketed for third parties and (iii) lower
transportation rates.
Drilling revenue associated with the Company's wholly-owned subsidiary,
Sauer increased 103% in 2000 to $11.5 million after remaining relatively
constant for 1998 and 1999. The increase in 2000 was attributable to higher rig
utilization rates and increased day rates resulting from the general increase in
activity within the oil and gas industry in 2000.
Costs and Expenses
Expenses related to gas and oil production increased 38% from 1999 to 2000
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 $.41 in 2000 from $.38 in 1999, due primarily
to the cost of operating the plant.
Expenses related to gas and oil production increased 27% from 1998 to 1999
due again to the Unocal acquisition.
Taxes on gas and oil production increased by 123% in 2000 and 32% in 1999
directly related to the increase in gas, oil and natural gas liquids sales in
these periods. The taxes for 1998 through 2000 have remained relatively constant
as a percentage of sales.
The Company's depletion, depreciation and amortization rates per Mcfe were
$.81, $.90, and $1.06 for years 2000, 1999 and 1998, respectively. The decrease
from 1998 to 1999, and 1999 to 2000, was primarily due to (i) lower finding and
development costs associated with the 2000 and 1999 reserve additions, (ii) the
impact of reducing the cost basis subject to amortization by the $51.3 million
property impairment recognized in 1998 and (iii) the increase in reserve
quantities (approximately 9%) resulting from upward revisions in the estimated
reserve quantities recognized in 2000.
Gathering and processing costs principally represents gas purchased in
conjunction with the gas gathering operation to replace gas physically lost in
the transmission process and all other costs associated with gathering and
processing. This expense increased in 2000 due to increased activity in the
gathering operations and as a result of the increase in the commodity price for
natural gas during this period.
Expenses associated with the Company's exploration activities were $11.0
million, $10.0 million and $17.3 million for the years 2000, 1999 and 1998,
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 resulting from an
overall reduction in capital spending levels for drilling and completion
activity. Capital expenditures in 2000 increased 140% in comparison to 1999. As
emphasis was placed upon reserve development during this period, exploration
expenses for 2000 remaining relatively unchanged in comparison to the prior
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, $.19, and $.17 for the years 2000, 1999
and 1998, respectively reflecting the addition of personnel each year. In 1999,
costs were
16
17
incurred in conjunction with the Company's decision to relocate its corporate
headquarters to Denver, Colorado.
Interest expense increased $.4 million in 2000 due to an increase in
interest rates during the year. Interest expense increased $1.3 million in 1999
to $5.6 million as compared to $4.3 million in 1998 due to increased debt
levels.
The Company recorded income tax provisions of $39.8 million and $4.3
million in 2000 and 1999, respectively, and an income tax benefit of $27.9
million in 1998, resulting in effective tax rates of 37.4%, 38.9% and 39.0%,
respectively. At December 31, 2000, the Company has a net operating loss
carryforward of approximately $13.8 million available to offset future taxable
income. Additionally, statutory depletion carryforwards of approximately $6.2
million and $5.3 million of AMT credits carryforwards are available to offset
future taxes. Based upon the operating results for 2000 and the present economic
environment for the oil and gas industry, the Company believes that it will
generate sufficient taxable income in 2001 to utilize these carryforwards.
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, 2000, 1999 and 1998 are as follows:
2000 1999 1998
---------- ---------- ----------
(IN MILLIONS)
CAPITAL AND EXPLORATION EXPENDITURES:
ACQUISITIONS:
Sauer Drilling Company .......................... $ 2.7 $ 1.4 $ 8.1
Unocal .......................................... -- 60.9 --
Other Rocky Mountain Assets ..................... 17.1 8.2 --
Other ........................................... -- 2.5 --
Exploration costs ................................. 18.4 12.0 22.8
Development costs ................................. 74.4 33.2 49.3
Acreage ........................................... 16.8 2.5 3.3
Gas gathering and processing ...................... 16.3 2.7 8.6
Other ............................................. 4.8 1.7 1.2
---------- ---------- ----------
$ 150.5 $ 125.1 $ 93.3
========== ========== ==========
FINANCING SOURCES:
Common stock issued ............................... 17.7 $ 65.2 $ .6
Net long term bank debt ........................... (27.0) 26.0 32.0
Advances from gas purchasers ...................... -- (24.5) 24.5
Proceeds from sale of assets ...................... 9.7 2.6 1.9
Cash flow from operations before changes in working
capital ......................................... 160.0 59.8 34.4
Working capital and other ......................... (9.9) (4.0) (.1)
---------- ---------- ----------
$ 150.5 $ 125.1 $ 93.3
========== ========== ==========
The Company anticipates capital and exploration expenditures between $185
to $205 million in 2001, $175 to $195 million allocated to exploration and
development activity. Approximately $35 to $40 million of the anticipated
capital program will be incurred on exploration and development opportunities
resulting from the acquisition of Stellarton in January of 2001. The timing of
most of the Company's capital expenditures is discretionary and there are no
material long-term
17
18
commitments associated with the Company's capital expenditure plans.
Consequently, the Company is able to adjust the level of its capital
expenditures as circumstances warrant. The level of capital expenditures by the
Company will vary in future periods depending on energy market conditions and
other related economic factors.
Historically, the Company has funded capital expenditures and working
capital requirements with both internally generated cash, borrowings and stock
transactions. Net cash flow provided by operating activities after changes in
working capital was $133.0 million for 2000 as compared to $38.9 million and
$60.1 million in 1999 and 1998, respectively. The decrease in 1999 was due
primarily to the receipt of $24.5 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 within the
Notes to 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 $125 million revolving line of
credit with a current borrowing base of $225 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, 2000 has not yet been made. The Company intends to have in place by
the end of the first quarter of 2001, a new combined United States and Canadian
credit facility with an initial borrowing base of $300 million and a $225
million facility. This will replace the existing $125 million facility in place
at December 31, 2000. To finance the Stellarton transaction in January 2001, the
Company borrowed $30 million under a bridge loan, and an additional $44.5
million from the Company's existing credit facility. These balances will be
incorporated into the revised credit facility.
At December 31, 2000, the aggregate outstanding balance under the Credit
Facility was $54 million, bearing interest at 7.9% per annum. The amount
available for borrowing under the Credit Facility at December 31, 2000 was $71
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, 2000. 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.)
Markets and Prices
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 none of the Company's domestic gas and oil
production has been presold at contractually specified prices. During 2000, the
average prices received for gas and oil by the Company were $3.46 per Mcf and
$21.49 per barrel, respectively, as compared to $2.04 Mcf and $15.20 per barrel
in 1999 and $1.85 per Mcf and $11.37 per barrel in 1998.
In December 2000, the Company believed that the pricing environment
provided a strategic opportunity to significantly reduce the price risk on a
portion of the Company's production and decided to implement a hedging program.
Accordingly, the Company entered into several natural gas costless collars (put
and call options) and natural gas basis swaps to correlate the NYMEX based
costless collars back to the various index delivery points where the Company's
gas is produced. These positions were intended to hedge approximately 40% of the
Company's expected 2001 domestic gas production.
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As of December 31, 2000, the Company had open natural gas costless price
collars and basis swaps on its production as follows:
Natural Gas Collars
----------------------------------------
2001 Volume Basis
Contract Period in MMBtu/d Floor/Ceiling Swaps
--------------- ---------- ------------- -----
First Quarter 70,000 $6.60/$9.06 ($.05)
Second Quarter 63,000 $4.32/$7.05 ($.28)
Third Quarter 60,000 $4.03/$6.73 ($.28)
Fourth Quarter 40,000 $4.14/$6.76 ($.27)
Year Average 58,000 $4.89/$7.51 ($.21)
Based upon the gas index price strip and quoted basis differentials on
January 1, 2001, the costless collars were in a $7.1 million loss position and
the basis contracts were in a $3.2 million gain position on that date.
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.
Donald L. Evans Resignation
Effective January 19, 2001, Donald L. Evans resigned as the Company's
Chairman and Chief Executive Officer to become the United States Secretary of
Commerce. Mr. Evans received a retirement payment of $1.5 million in cash. In
addition, the Company accelerated the vesting of his outstanding stock options
resulting in a non-cash, pre-tax charge to earnings of approximately $3.8
million. Both the retirement payment and the non-cash charge for the
acceleration of the stock options will be recognized by the Company in the first
quarter of 2001.
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.
Derivative Financial Instruments
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
19
20
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 ("FASB") 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. In June 2000, the
FASB issued SFAS 138, "Accounting for Certain Derivative Instruments and Certain
Hedging Activities". This pronouncement amended portions of SFAS 133 and was
adopted by the Company with SFAS 133 effective January 1, 2001.
SFAS 133, in part, allows special hedge accounting for cash flow hedges and
provides that the effective portion of the gain or loss on a derivative
instrument designated and qualifying as a cash flow hedging instrument be
reported as a component of Other Comprehensive Income and be reclassified into
earnings in the same period or periods during which the hedged forecasted
transaction affects earnings.
The Company has certain cash flow hedges in place (natural gas costless
collar arrangements), which were open as of January 1, 2001 when SFAS 133 and
SFAS 138 became effective. Based upon the natural gas index pricing strip in
effect as of January 1, 2001, the impact of these hedges at adoption would
result in a charge to Other Comprehensive Income of $4.5 million (net of the
deferred tax benefit of $2.6 million) and the recognition of a derivative
liability of $7.1 million.
The Company also entered into natural gas basis swaps covering essentially
the same time period of the natural gas costless collars. These transactions
were executed in December, 2000 with settlement periods in 2001. Under SFAS 133,
these basis swaps will not qualify for hedge accounting. Accordingly, upon
adoption these basis swaps would result in the recognition of derivative gains
of $2.0 million, recorded as the cumulative effect of a change in accounting
principle, (net of the deferred tax liability of $1.2 million) and a derivative
receivable of $3.2 million.
Interest Rate Risk
At December 31, 2000, the Company had $54 million outstanding under its
credit facility at an average interest rate of 7.9%. 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 2000 will
fluctuate based on short-term interest rates. Assuming no change in the amount
outstanding during 2001, the impact on interest expense of a ten percent change
in the average interest rate would be approximately $427,000. As the interest
rate is variable and is reflective of current market conditions, the carrying
value of the credit facility approximates the fair value.
20
21
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Report of Independent Public Accountants.................... 22
Consolidated Balance Sheets, December 31, 2000 and 1999..... 23
Consolidated Statements of Operations, Years ended December
31, 2000, 1999 and 1998................................... 24
Consolidated Statements of Changes in Stockholders' Equity,
Years ended December 31, 2000, 1999 and 1998.............. 25
Consolidated Statements of Cash Flows, Years ended December
31, 2000, 1999 and 1998................................... 26
Notes to Consolidated Financial Statements.................. 27
21
22
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Shareholders of Tom Brown, Inc.:
We have audited the accompanying consolidated balance sheets of Tom Brown,
Inc. (a Delaware corporation) and subsidiaries as of December 31, 2000 and 1999,
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, 2000. 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 financial statements referred to above present fairly,
in all material respects, the financial position of Tom Brown, Inc. and
subsidiaries as of December 31, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.
ARTHUR ANDERSEN LLP
Denver, Colorado
February 22, 2001
22
23
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
DECEMBER 31,
-----------------------------
2000 1999
------------ ------------
(IN THOUSANDS)
CURRENT ASSETS:
Cash and cash equivalents ............................................ $ 17,534 $ 12,510
Accounts receivable .................................................. 95,878 53,646
Inventories .......................................................... 521 828
Other ................................................................ 2,307 1,625
------------ ------------
Total current assets ........................................ 116,240 68,609
------------ ------------
PROPERTY AND EQUIPMENT, AT COST:
Gas and oil properties, successful efforts method of
accounting ....................................................... 575,991 470,461
Gas gathering and processing and other plant ......................... 81,873 71,657
Other ................................................................ 28,746 23,027
------------ ------------
Total property and equipment ............................... 686,610 565,145
Less: Accumulated depreciation, depletion and
amortization ...................................................... 176,848 133,342
------------ ------------
Net property and equipment .................................. 509,762 431,803
------------ ------------
OTHER ASSETS:
Deferred income taxes, net ........................................... -- 28,625
Other assets ......................................................... 3,533 35,887
------------ ------------
$ 629,535 $ 536,299
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable ....................................................... $ 55,982 $ 39,489
Accrued expenses ....................................................... 22,119 9,763
------------ ------------
Total current liabilities ...................................... 78,101 49,252
------------ ------------
BANK DEBT ................................................................ 54,000 81,000
DEFERRED INCOME TAXES .................................................... 5,475 --
OTHER NON-CURRENT LIABILITIES ............................................ 3,066 3,950
COMMITMENTS AND CONTINGENCIES (Note 13)
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 in 1999 .................................. -- 100
Common Stock, $.10 par value
Authorized 55,000,000 shares;
Outstanding 38,351,860 shares and 35,308,489 shares,
respectively ....................................................... 3,835 3,531
Additional paid-in capital ............................................. 516,706 95,817
Accumulated deficit .................................................... (31,648) 97,351)
------------ ------------
Total stockholders' equity ..................................... 488,893 402,097
------------ ------------
$ 629,535 $ 536,299
============ ============
See accompanying notes to consolidated financial statements.
23
24
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31,
----------------------------------------------
2000 1999 1998
------------ ------------ ------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
REVENUES:
Gas, oil and natural gas liquids sales ............ $ 216,968 $ 104,431 $ 78,072
Gathering and processing .......................... 18,283 11,968 9,061
Marketing and trading, net ........................ 5,841 (786) (2,471)
Drilling .......................................... 11,472 5,645 4,561
Interest income and other ......................... 1,346 2,153 716
------------ ------------ ------------
Total revenues ............................ 253,910 123,411 89,939
------------ ------------ ------------
COSTS AND EXPENSES:
Gas and oil production ............................ 25,488 18,446 14,522
Taxes on gas and oil production ................... 22,105 9,934 7,512
Gathering and processing costs .................... 7,212 5,853 7,051
Drilling operations ............................... 9,715 5,237 4,367
Exploration costs ................................. 11,001 10,013 17,274
Impairments of leasehold costs .................... 3,900 3,600 3,215
General and administrative ........................ 11,747 9,503 7,139
Depreciation, depletion and amortization .......... 50,417 44,215 44,575
Impairment of gas and oil properties .............. -- -- 51,344
Interest expense .................................. 5,967 5,560 4,301
------------ ------------ ------------
Total costs and expenses .................. 147,552 112,361 161,300
------------ ------------ ------------
Income (loss) before income taxes ......... 106,358 11,050 (71,361)
Income tax (provision) benefit
Current ........................................... (1,968) (903) (1,611)
Deferred .......................................... (37,812) (3,390) 29,489
------------ ------------ ------------
Net income (loss) ................................... 66,578 6,757 (43,483)
Preferred stock dividends ........................... (875) (1,750) (1,750)
------------ ------------ ------------
Net income (loss) attributable to common stock ...... $ 65,703 $ 5,007 $ (45,233)
============ ============ ============
Weighted average number of common shares outstanding:
Basic ............................................. 36,664 32,228 29,251
============ ============ ============
Diluted ........................................... 37,897 32,466 29,251
============ ============ ============
Net income (loss) per common share:
Basic ............................................. $ 1.79 $ .16 $ (1.55)
============ ============ ============
Diluted ........................................... $ 1.76 $ .15 $ (1.55)
============ ============ ============
See accompanying notes to consolidated financial statements.
24
25
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,
1997 ........................ 1,000 $ 100 29,210 $ 2,921 $ 430,502 $ (57,125) $ 376,398
Stock options exercised,
including income tax
benefit ..................... -- -- 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,
including income tax
benefit ..................... -- -- 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
Stock options exercised,
including income tax
benefit ..................... -- -- 1,378 137 21,254 -- 21,391
Unrealized loss on marketable
securities .................. -- -- -- -- (298) -- (298)
Net income ..................... -- -- -- -- -- 66,578 66,578
Preferred stock dividends ...... -- -- -- -- -- (875) (875)
Preferred stock conversion ..... (1,000) (100) 1,666 167 (67) -- --
--------- --------- --------- --------- --------- --------- ---------
BALANCE AS OF DECEMBER 31,
2000 ........................ -- $ -- 38,352 $ 3,835 $ 516,706 $ (31,648) $ 488,893
========= ========= ========= ========= ========= ========= =========
See accompanying notes to consolidated financial statements.
25
26
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31,
-------------------------------------
2000 1999 1998
--------- --------- ---------
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) .......................................... $ 66,578 $ 6,757 $ (43,483)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization ................. 50,417 44,215 44,575
(Gain) loss on sales of assets ........................... -- (1,265) 27
Impairment of gas and oil properties ..................... -- -- 51,344
Deferred tax provision (benefit) ......................... 37,812 3,390 (29,408)
Dry hole costs ........................................... 1,249 3,124 8,134
Impairments of leasehold costs ........................... 3,900 3,600 3,215
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable ............ (42,232) (19,140) 8,559
(Increase) decrease in inventories .................... 307 (296) (167)
(Increase) decrease in other current assets ........... (1,541) (616) 11
Increase (decrease) in accounts payable and accrued
expenses ............................................ 15,549 22,644 (4,451)
(Increase) decrease in other assets, net .............. 919 973 (2,785)
Advances from gas purchasers .......................... -- (24,529) 24,529
--------- --------- ---------
Net cash provided by operating activities .................... 132,958 38,857 60,100
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sales of assets .............................. 9,681 2,573 1,870
Capital and exploration expenditures ....................... (140,719) (56,183) (84,134)
Changes in accounts payable and accrued expenses for
capital expenditures ..................................... 13,300 (1,389) (7,370)
--------- --------- ---------
Net cash used in investing activities ........................ (117,738) (54,999) (89,634)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings of long-term bank debt .......................... 20,000 26,000 106,000
Repayments of long-term bank debt .......................... (47,000) -- (74,000)
Repayments of note payable, current ........................ -- -- (5,168)
Preferred stock dividends .................................. (875) (1,750) (1,750)
Proceeds from exercise of stock options .................... 17,679 1,732 585
--------- --------- ---------
Net cash (used in) provided by financing activities .......... (10,196) 25,982 25,667
--------- --------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ......... 5,024 9,840 (3,867)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR ............... 12,510 2,670 6,537
--------- --------- ---------
CASH AND CASH EQUIVALENTS AT END OF YEAR ..................... $ 17,534 $ 12,510 $ 2,670
========= ========= =========
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest ................................................... $ 4,941 $ 4,051 $ 3,985
Income taxes ............................................... 840 -- 308
Supplemental schedule of noncash investing and financing
activities: (see Notes 2 and 3)
Common stock issued as consideration in connection with
Unocal Acquisition ....................................... $ -- $ 63,515 $ --
Common stock received for outstanding receivable ........... -- 700 --
See accompanying notes to consolidated financial statements.
26
27
TOM BROWN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(1) NATURE OF OPERATIONS
Tom Brown, Inc. and its wholly-owned subsidiaries (the "Company") is an
independent energy company engaged in the 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"), Wildhorse Energy Partners, L. L. C. ("Wildhorse")and TBI Field
Services, Inc. ("TBIFS") 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 United States 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. In 2000, the Company expanded its operations in Canada establishing
western Canada as a core area through the acquisition of Stellarton Energy
Corporation (see footnote 15). This transaction was completed in January, 2001.
Wildhorse was originally formed by KN Energy, Inc. ("KNE") and the Company
in January 1996. KNE was subsequently acquired by Kinder Morgan Inc. ("KM").
Initially, Wildhorse was owned fifty-five percent (55%) by KNE and forty-five
percent (45%) by the Company. The Company dedicated a significant amount of its
Rocky Mountain gas reserves to Wildhorse and KNE contributed substantial gas
marketing contracts. The Company also transferred a natural gas storage facility
in western Colorado to Wildhorse. The principal purpose of Wildhorse was 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. Firm
transportation contracts were also assigned 55% to KM and 45% to Retex at that
time. In November 2000, the remaining gathering and processing assets were
distributed to the Company in anticipation of the dissolution of Wildhorse. KM
received the storage facility and a cash payment. TBIFS was formed as a
wholly-owned subsidiary of Tom Brown, Inc. to administer the gathering and
processing assets received in the Wildhorse distribution.
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 2000 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 are
consolidated within the accompanying financial statements. All significant
intercompany accounts and transactions have been eliminated. Certain
27
28
reclassifications have been made to amounts reported in previous years to
conform to the 2000 presentation.
Inventories
Inventories consist of pipe and other production equipment. Inventories are
stated at the lower of cost (principally first-in, first-out) or estimated net
realizable value.
Property and Equipment
The Company accounts for its natural gas and crude oil exploration and
development activities under the successful efforts method of accounting. Under
such method, costs of productive exploratory wells, development dry holes and
productive wells and undeveloped leases are capitalized. Gas and oil lease
acquisition costs are also capitalized. Exploration costs, including personnel,
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. The sale of a partial
interest in a proved property is accounted for as a cost recovery and no gain or
loss is recognized as long as this treatment does not significantly affect the
unit-of-production amortization rate. A gain or loss is recognized for all other
sales of producing properties.
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. Proceeds from
sales of partial interests in unproved leases are accounted for as a recovery of
cost without recognizing any gain or loss.
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 2000 or 1999.
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
28
29
share of gas revenues. Using historical prices, the Company had net gas
balancing liabilities of approximately $1.2 million and $1.9 million associated
with approximately .7 billion and 1.3 billion cubic feet ("Bcf") of gas at
December 31, 2000 and 1999, 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 ("FASB") 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. In June 2000, the
FASB issued SFAS 138, "Accounting for Certain Derivative Instruments and Certain
Hedging Activities". This pronouncement amended portions of SFAS 133 and was
adopted by the Company with SFAS 133 effective January 1, 2001.
SFAS 133, in part, allows special hedge accounting for cash flow hedges and
provides that the effective portion of the gain or loss on a derivative
instrument designated and qualifying as a cash flow hedging instrument be
reported as a component of Other Comprehensive Income and be reclassified into
earnings in the same period or periods during which the hedged forecasted
transaction affects earnings.
The Company has certain cash flow hedges in place (natural gas costless
collar arrangements) which were open as of January 1, 2001 when SFAS 133 and
SFAS 138 became effective. Based upon the natural gas index pricing strip in
effect as of January 1, 2001, the impact of these hedges at adoption resulted in
a charge to Other Comprehensive Income of $4.5 million (net of the deferred tax
benefit of $2.6 million) and the recognition of a derivative liability of $7.1
million.
The Company also entered into natural gas basis swaps covering essentially
the same time period of the natural gas costless collars. These transactions
were executed in December, 2000 with settlement periods in 2001. Under SFAS 133,
these basis swaps will not qualify for hedge accounting. Accordingly, upon
adoption these basis swaps would result in the recognition of derivative gains
of $2.0 million, recorded as a cumulative effect of a change in accounting
principle, (net of the deferred tax liability of $1.2 million) and a derivative
receivable of $3.2 million.
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30
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 2000, 1999 and 1998.
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.
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,
2000, 1999 and 1998:
2000 1999 1998
------------------------------ -------------------------------- -------------------------------
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 .. $ 65,703 36,664 $ 1.79 $ 5,007 32,228 $ .16 $(45,233) 29,251 $ (1.55)
Dilutive Securities:
Stock Options .............. -- 473 -- -- 238 -- -- -- --
Convertible preferred stock 875 760 -- -- -- -- -- -- --
-------- -------- --------- -------- -------- ---------- -------- -------- --------
Diluted EPS:
Net Income (Loss)
Attributable to Common
Stock and Assumed Share
Amounts .................. $ 66,578 37,897 1.76 $ 5,007 32,466 $ .15 $(45,233) 29,251 $ (1.55)
======== ======== ========= ======== ======== ========== ======== ======== ========
Options to purchase 1,447,000 shares of common stock in 1999 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.
No options were excluded in 2000. Shares of common stock issuable upon
conversion of preferred stock were excluded in the computation of diluted
earnings per share in 1999 and 1998 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.
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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 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.
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 years ended December 31, 2000 and 1999 was an
unrealized (loss)/gain on marketable securities of $(298,000) and $93,000,
respectively. There were no such reconciling items for the year ended December
31, 1998.
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 and transition payments made in 1999 and 2000 of $1.0
million and $.8 million, respectively. An additional accrual of $.3 million was
made for future rental obligations for years 2000 through 2003.
(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...................................... $37.5
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 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.
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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 June 2000, the Company purchased an additional working interest in a
field operated by the Company in the Wind River Basin in Wyoming. The acquired
interests included an estimated 24.0 Bcfe of proved reserves purchased for total
consideration of $15.2 million net of normal closing adjustments.
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. ("Sauer") 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.
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 which was
included in other income. 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 entered into a $75 million credit facility (the
"Credit Facility") that had a maturity of April 2001. In October 1998, the
Company amended the Credit Facility by increasing the total borrowing amount to
$100 million. The borrowing base was again increased in October 1999 as a result
of the regular June 30 review which reflected the impact of the Unocal
Acquisition. As of December 31, 1999, the outstanding balance was $81 million on
the Credit Facility at an average interest rate of 6.9%.
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On June 30, 2000, the Company repaid and cancelled its $100 million
revolving Credit Facility and entered into a new $125 million credit facility
(the "New Credit Facility") that matures in June 2003. Under the terms of the
New Credit Facility, the borrowing base was increased from $190 million to $225
million and the maturity date was extended beyond the April 2001 maturity date
in the cancelled credit facility. The amount of the borrowing base may be
redetermined as of December 31 of each calendar year at the sole discretion of
the lender. The borrowing base may also be redetermined in the event outstanding
borrowings exceed 50% of the borrowing base. At December 31, 2000, the
outstanding balance on the New Credit Facility was $54 million at an average
interest rate of 7.9%.
Borrowings under the New Credit Facility are unsecured and bear interest,
at the election of the Company, at a rate equal to (i) the greater of the agent
bank's prime rate or the federal funds effective rate plus an applicable margin
or (ii) the agent bank's Eurodollar rate plus an applicable margin. Interest on
amounts outstanding under the New Credit Facility is due on the last day of each
quarter 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.
The New Credit Facility contains certain financial covenants and other
restrictions similar to the limitations associated with the cancelled credit
facility. The financial covenants of the New Credit Facility require the Company
to maintain a minimum consolidated tangible net worth of not less than $325
million and the Company is required to maintain a ratio of (i) earnings before
interest expense, state and Federal taxes, depreciation, depletion and
amortization expense and exploration expense to (ii) consolidated fixed charges,
as defined in the New Credit Facility, of not less than 2.5:1. Additionally, the
Company is required to maintain a ratio of consolidated debt to consolidated
total capitalization of less than 0.45:1.
(5) TAXES
The Company has not paid Federal income taxes due to its net operating loss
carryforward, but is required to pay alternative minimum tax ("AMT"). This tax
can be partially offset by an AMT net operating loss carryforward. A U.S.
Federal statutory rate applied to the Company's income (loss) before income
Taxes of 35% in 2000, 1999 and 1998 was used in the following reconciliation of
the Company's effective income tax benefit (provision):
YEARS ENDED DECEMBER 31,
------------------------------------------------
2000 1999 1998
------------ ------------ ------------
(IN THOUSANDS)
Federal income tax (provision) benefit at statutory
rate ............................................... $ (37,225) $ (3,868) $ 24,976
Adjustment to valuation allowance .................... 1,953 622 2,980
Other, net ........................................... (2,540) (144) 1,533
------------ ------------ ------------
(37,812) (3,390) 29,489
AMT provisions ....................................... (850) -- (380)
State income and franchise taxes ..................... (1,118) (903) (1,231)
------------ ------------ ------------
Income tax (provision) benefit ....................... $ (39,780) $ (4,293) $ 27,878
============ ============ ============
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The significant components, which give rise to the Company's deferred tax
assets (liabilities), are as follows:
DECEMBER 31,
------------------------------
2000 1999
------------ ------------
(IN THOUSANDS)
Net operating loss carryforward ............................................. $ 4,845 $ 18,211
Gas and oil acquisition, exploration and development costs
deducted for tax purposes (over) under book................................ (17,877) 3,735
AMT Credit Carryforwards .................................................... 5,343 4,493
Investment tax credit carryforward .......................................... -- 195
Option plan compensation .................................................... -- 1,559
Other ....................................................................... 2,214 2,385
------------ ------------
Net deferred tax (liability) asset .......................................... (5,475) 30,578
Valuation allowance ......................................................... -- (1,953)
------------ ------------
Net deferred tax (liability) asset .......................................... $ (5,475) $ 28,625
============ ============
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
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. In 2000, it
was determined that the Company was unlikely to realize any future tax benefit
from the investment tax credit carryforwards and the option compensation which
resulted in the elimination of these deferred tax assets and the associated
valuation allowance. Based on its recent operating results and its expected
levels of future earnings, the Company believes it will, more likely than not,
generate sufficient taxable income to realize the benefit attributable to the
net operating loss carryforward and other deferred tax assets for which
valuation allowances were not provided.
At December 31, 2000, the Company had a net operating loss carryforward of
approximately $13.8 million. The Company has no current liability for Federal
income taxes because of this net operating loss carryforward. Realization of the
benefits of this carryforward is dependent upon the Company's ability to
generate taxable earnings in future periods. In addition, the availability of
this carryforward is subject to various limitations. The net operating loss
carryforward expires in 2019. Additionally, the Company has approximately $6.2
million of statutory depletion carryforwards and $5.3 million of AMT credit
carryforwards that may be carried forward until utilized.
(6) ADVANCES FROM GAS PURCHASERS
In 1998, the Company received $24.5 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) TRADING ACTIVITIES
The Company engages in natural gas trading activities which involve
purchasing natural gas from third parties and selling natural gas to other
parties. These transactions are typically short-term in nature and involve
positions whereby the
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35
underlying quantities generally offset. The Company also markets a significant
portion of its own production. Marketing and trading income associated with
these activities is presented on a net basis in the financial statements. The
Company's gross trading activities are summarized below.
YEARS ENDED DECEMBER 31,
-----------------------------------------------
2000 1999 1998
------------ ------------ ------------
(IN THOUSANDS)
Revenues $ 111,756 $ 68,013 $ 29,804
Operating expenses 108,370 68,524 31,411
------------ ------------ ------------
Net trading margin $ 3,386 $ (511) $ (1,607)
============ ============ ============
(8) 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, 2000, of which
38,351,860 shares and 35,308,489 shares were outstanding at December 31, 2000
and 1999, 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).
Rights Plan
On March 1, 1991, the Board of Directors adopted a Rights Plan designed to
help assure that all stockholders receive fair and equal treatment in the event
of a hostile attempt to take over the Company, and to help guard against abusive
takeover tactics. The Board of Directors declared a dividend of one preferred
share purchase right (a "Right") for each outstanding share of Common Stock. The
dividend was distributed on March 15, 1991 to the shareholders of record on that
date. As of March 1, 2001, the Board of Directors amended and restated the
Rights Plan. Each Right entitles the registered holder to purchase, for the $120
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 15% or
more of the Company's Common Stock or announces a tender offer which would
result in ownership by a person or group of 15% 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 1, 2011, 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.
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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 was 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.
The Preferred Stock was 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").
On June 15, 2000, the Company elected to exchange 1,666,000 shares of its
common stock for all 1,000,000 outstanding shares of the preferred Stock as the
common stock had traded above the Threshold Price. Dividends on the Preferred
Stock were paid through June 14, 2000 and will no longer accrue after the June
15, 2000 exchange date. The Preferred Stock is no longer outstanding.
(9) 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, 2000, options to purchase 696,300 shares of the Company's common
stock were outstanding under the 1989 Plan.
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. Options to purchase 2,226,000 shares of the
Company's common stock were outstanding under this plan as of December 31, 2000.
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 and options to purchase 490,000 shares of the
Company's common stock were granted in 2000. 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.
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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,
-------------------------------------------------------
2000 1999 1998
---------------- ------------------ ----------------
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..... 4,139 13.77 3,402 $13.22 2,173 $12.84
Granted............................ 852 15.14 1,178 13.91 2,127 16.04
Exercised.......................... (1,378) 12.67 (248) 6.98 (50) 11.80
Cancellations...................... (201) 14.77 (193) 13.56 (848) 19.43
------ ----- -----
Outstanding, end of year........... 3,412 14.52 4,139 13.77 3,402 13.22
====== ===== =====
Exercisable, end of year........... 1,659 14.22 2,226 13.10 1,919 11.64
====== ===== =====
Available for grant, end of year... 1,722 2,392 945
====== ===== =====
The weighted average fair value of options granted during the years ended
December 31, 2000, 1999, and 1998 was $9.78, $9.72, and $9.01, respectively.
The following table summarizes information about stock options outstanding
at December 31, 2000:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------- ------------------------
WTD. AVG.
NO. OF SHS. REMAINING NO. OF SHS.
UNDER CONTRACTUAL WTD. AVG. UNDER WTD. AVG.
RANGE OF OUTSTANDING LIFE EXERCISE EXERCISABLE EXERCISE
EXERCISE PRICES OPTIONS (YEARS) PRICE OPTIONS PRICE
- --------------- ----------- ----------- --------- ------------ ---------
(SHARES IN THOUSANDS)
$ 3.81 to 13.00........................ 853 7.60 $11.54 327 $ 9.89
$13.50 to 15.25........................ 1,080 6.35 14.03 439 14.42
$15.69 to 24.19........................ 1,479 7.65 16.59 893 15.71
----- -----
3,412 7.23 14.52 1,659 14.22
===== =====
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,
--------------------------
2000 1999 1998
------ -------- ------
(IN THOUSANDS,
EXCEPT PER SHARE AMOUNTS)
Net Income (loss)
As Reported............................................... $65,703 $5,007 $(45,233)
Pro Forma................................................. $63,693 $ 451 $(48,645)
Basic Net Income (loss) per Common Share:
As Reported............................................... $ 1.79 $ .16 $ (1.55)
Pro Forma................................................. $ 1.74 $ .01 $ (1.66)
Diluted Net Income (loss) per Common Share:
As Reported............................................... $1.76 $ .15 $ (1.55)
Pro Forma................................................. $1.70 $ .01 $ (1.66)
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
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used for grants in 2000, 1999, and 1998, respectively: (i) risk-free interest
rates of 6.25%, 6.20, and 5.54 percent; (ii) expected lives of 7.0, 7.0 and 7.3
years, (iii) expected volatility of 53.7, 47.6, and 44.3 percent, and (iv) no
dividend yields.
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. Effective January 1, 2000, the Company adopted a
401(k) retirement plan that superseded the KSOP plan. The Company has, at its
discretion, a policy to match employee contributions to the plan. As of December
31, 2000, 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, 2000, 1999 and 1998, was approximately
$492,000, $422,000 and $329,000, respectively.
(10) 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.
Commodity Price Swaps
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.
The Company has entered into natural gas and crude oil futures contracts
with counter parties to hedge the price risk associated with a portion of its
production. These derivatives are not held for trading purposes. To the extent
that changes occur in the market prices of natural gas and oil, the Company is
exposed to market risk on these open contracts. This market risk exposure is
generally offset by the gain or loss recognized upon the ultimate sale of the
commodity hedged.
In December 2000, the Company entered into several costless price collar
arrangements (put and call options) to hedge approximately 40% of the Company's
expected 2001 U.S. gas production. As of January 1, 2001 SFAS 133 and SFAS 138
became effective. The costless price collars have two components of value:
intrinsic and time value. Under SFAS 133, both components will be valued at the
end of each reporting period. Intrinsic value arises when the index price is
either above the ceiling or below the floor for any period covered by the
collar. If the index is above the ceiling for any month covered by the collar,
the intrinsic value would be the difference between the index and the ceiling
prices multiplied by the notional volume. Intrinsic value related to each
reporting period would be recorded
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as a hedge loss (if the index is above the ceiling) or gain (if the index is
below the floor).
Starting in 2001 under SFAS 133, any changes in the intrinsic value
component of the derivative instrument related to future months will be recorded
in Other Comprehensive Income, a component of equity, rather than directly to
earnings to the extent that the hedge is proven to be effective. Amounts
recorded in Other Comprehensive Income will be reclassified to earnings in the
same period during which the hedged forecasted transactions affects earnings.
Also under SFAS 133, the time value component of the derivative instrument, a
market premium or discount, is marked-to-market through the statement of
operations each period.
As of December 31, 2000, the Company had open natural gas costless price
collars and basis swaps on its production as follows:
Natural Gas Collars
---------------------------------------
2001 Volume Basis
Contract Period in MMBtu/d Floor/Ceiling Swaps
--------------- ---------- ------------- -----
First Quarter 70,000 $6.60/$9.06 ($.05)
Second Quarter 63,000 $4.32/$7.05 ($.28)
Third Quarter 60,000 $4.03/$6.73 ($.28)
Fourth Quarter 40,000 $4.14/$6.76 ($.27)
Year Average 58,000 $4.89/$7.51 ($.21)
Based upon the gas index price strip and quoted basis differentials on January
1, 2001, the costless collars and basis swaps were in a net $3.9 million loss
position.
(11) 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 a law firm that previously employed one of the
Company's directors as a partner. The amounts paid to this firm for the years
ended December 31, 2000, 1999 and 1998, were approximately $162,000, $97,000 and
$100,000, respectively. The Company also paid approximately $44,000, $38,000 and
$35,000 during the years ended December 31, 2000, 1999 and 1998, 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,
2000, 1999, and 1998, the Company billed $612,000, $579,000 and $508,000,
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 and 1998, the Company charged the former
subsidiary approximately $67,000 and $86,000, respectively, for such services.
The former subsidiary performs drilling services on certain wells operated by
the Company and charged approximately $787,000, $1,860,000, and $1,643,000 for
such services during the years ended December 31, 2000, 1999 and 1998,
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.
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Significant Customers
Gas and oil sales to Conoco, Inc. accounted for 11%, 12% and 24% of gas and
oil sales and marketing, gathering and processing revenues for the years ended
December 31, 2000, 1999 and 1998, 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.
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.
(12) 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, Wildhorse and TBIFS, 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 the 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, 2000
---------------------------------------------------------------
GAS & OIL MARKETING,
EXPLORATION GATHERING
& & TOTAL
DEVELOPMENT PROCESSING DRILLING SEGMENTS
------------ ------------ ------------ ------------
Revenues from external purchasers ................ $ 153,026 $ 229,100 $ 11,472 $ 393,598
Intersegment revenues ............................ 55,150 -- 6,309 61,459
Depreciation, depletion and amortization ......... 46,853 2,959 1,707 51,519
Segment profit ................................... 99,243 12,165 1,635 113,043
Assets ........................................... 545,639 110,438 13,612 669,689
Capital and exploration expenditures ............. 132,117 16,347 2,725 151,189
40
41
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
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
The following tables reconcile segment information to consolidated totals:
DECEMBER 31,
---------------------------------------
2000 1999 1998
--------- --------- ---------
Revenues
Revenue from external purchasers ................... $ 393,598 $ 207,468 $ 122,857
Marketing and trading expenses offset against
related revenues for net presentation .......... (148,480) (91,439) (41,391)
Intersegment revenues .............................. 61,459 25,713 20,523
Intercompany eliminations .......................... (52,667) (18,331) (12,050)
--------- --------- ---------
Total consolidated revenues ................ $ 253,910 $ 123,411 $ 89,939
========= ========= =========
Profit or (loss)
Total reportable segment profit/loss ............... $ 113,043 $ 17,151 $ (66,514)
Interest expense ................................... (5,967) (5,560) (4,301)
Eliminations and other ............................. (718) (541) (546)
--------- --------- ---------
Income (loss) before income taxes .................. $ 106,358 $ 11,050 $ (71,361)
========= ========= =========
Depreciation, depletion and amortization
Total reportable segment depreciation, depletion and
amortization .................................... $ 51,519 $ 44,963 $ 45,253
Eliminations and other ............................. (1,102) (748) (678)
--------- --------- ---------
$ 50,417 $ 44,215 $ 44,575
========= ========= =========
Assets
Total reportable segment assets .................... $ 669,689 $ 567,156 $ 444,226
Eliminations and other ............................. (40,154) (30,857) (2,344)
--------- --------- ---------
$ 629,535 $ 536,299 $ 441,882
========= ========= =========
(13) 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.
41
42
Lease Commitments
At December 31, 2000, 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)
2001 .................... $ 1,268
2002 .................... 1,258
2003 .................... 1,265
2004 .................... 84
Thereafter .............. --
----------
$ 3,875
==========
Total rental expense incurred for the years ended December 31, 2000, 1999
and 1998, was approximately $1,447,000, $1,139,000, and $1,043,000,
respectively, all of which represented minimum rentals under non-cancelable
operating leases.
Firm Transportation Commitments
On September 1, 1999, the Company took assignment of firm transportation
commitments within Wildhorse based upon its 45% interest in Wildhorse.
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)
2001.................................................... $ 4,841
2002.................................................... 4,035
2003.................................................... 3,322
2004.................................................... 2,210
2005.................................................... 1,443
Thereafter.............................................. 1,003
-------
$16,854
=======
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, 2000. 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.
(14) SUBSEQUENT EVENT
On January 12, 2001, the Company completed an acquisition of 97.2% of the
outstanding common shares of Stellarton Energy Corporation ("Stellarton"). The
remaining shares of Stellarton were then subsequently acquired pursuant to the
compulsory acquisitions provisions of the Business Corporation Act (Alberta).
Including assumed debt of approximately $14.5 million, this business combination
had a value of approximately $95 million and will be accounted for as a
purchase. The purchase price exceeded the fair value of the net assets of
Stellarton by $10.8
42
43
million which will be amortized on a straight-line basis over twenty years. The
results of operations of Stellarton will be included with the results of the
Company from January 12, 2001 (closing date) forward.
(15) QUARTERLY FINANCIAL DATA (UNAUDITED)
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER TOTAL
------------ ------------ ------------ ------------ ------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Year ended December 31, 2000
Revenues .................................. $ 74,158 $ 89,713 $ 101,712 $ 136,807 $ 402,390
Gross profit(1) ........................... 29,952 39,506 48,185 68,644 186,287
Net income attributable to common
stock ................................... 7,271 12,165 17,103 29,164 65,703
Net income per common share(2)
Basic ................................... .21 .34 .46 .77 1.79
Diluted ................................. .20 .33 .44 .73 1.76
Year ended December 31, 1999
Revenues .................................. $ 20,644 $ 23,953 $ 35,691 $ 43,123 $ 123,411
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
- ----------
(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.
(16) 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,
------------------------------------------------
2000 1999 1998
------------ ------------ ------------
(IN THOUSANDS)
Capitalized costs
Proved gas and oil properties ................. $ 526,269 $ 427,676 $ 344,766
Unproved gas and oil properties ............... 49,722 42,785 42,570
------------ ------------ ------------
Total gas and oil properties .................. 575,991 470,461 387,336
Less: Accumulated depreciation, depletion and
amortization ............................. (160,738) (116,403) (78,161)
------------ ------------ ------------
Net capitalized costs ......................... $ 415,253 $ 354,058 $ 309,175
============ ============ ============
43
44
YEARS ENDED DECEMBER 31,
----------------------------------------------
2000 1999 1998
------------ ------------ ------------
(IN THOUSANDS)
Costs incurred
Proved property acquisition costs(1) $ 17,111 $ 65,753 $ --
Unproved property acquisition costs 16,831 6,945 3,283
Exploration costs .................. 18,362 12,016 22,844
Development costs .................. 74,406 33,232 49,262
------------ ------------ ------------
Total .................... $ 126,710 $ 117,946 $ 75,389
============ ============ ============
(1) For 1999 proved property acquisition costs includes $19.9 million for a gas
processing plant acquired 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 and
1998, were principally prepared by independent petroleum consultants. The
reserve estimates for the year ended December 31, 2000 were prepared by the
Company's petroleum engineering staff and audited by the 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.
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.
44
45
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, 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
Revisions of previous estimates ........... 50,852 (311)
Purchases of minerals in place ............ 28,960 17
Extensions and discoveries ................ 60,827 470
Sales of minerals in place ................ -- (137)
Production ................................ (51,199) (1,847)
---------- ----------
Estimated reserves at December 31, 2000 ..... 535,373 11,193
========== ==========
Proved developed reserves:
December 31, 1997 ......................... 258,756 5,749
December 31, 1998 ......................... 263,747 4,029
December 31, 1999 ......................... 333,858 11,398
December 31, 2000 ......................... 431,824 10,089
(1) Oil volumes include natural gas liquids which were insignificant until
1999. For 1999, purchases of minerals in place and production include
6.0 million and 0.5 million barrels, respectively, 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. In 2000, liquids production was 1.1 million barrels and
5.1 million barrels of proved developed reserves of natural gas
liquids remained at December 31, 2000.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Gas and Oil Reserves (Unaudited)
DECEMBER 31,
---------------------------------------------
2000 1999 1998
----------- ----------- -----------
(IN THOUSANDS)
Future cash flows ..................................... $ 5,028,357 $ 1,107,515 $ 764,974
Future production costs ............................... (857,767) (320,397) (217,632)
Future development costs .............................. (89,216) (85,712) (74,371)
----------- ----------- -----------
Future net cash flows before tax ...................... 4,081,374 701,406 472,971
Future income taxes ................................... (1,409,295) (119,950) (71,960)
----------- ----------- -----------
Future net cash flows after tax ....................... 2,672,079 581,456 401,011
Annual discount at 10% ................................ (1,196,324) (247,897) (179,294)
----------- ----------- -----------
Standardized measure of discounted future net cash
flows ............................................... $ 1,475,755 $ 333,559 $ 221,717
=========== =========== ===========
Discounted future net cash flows before income taxes .. $ 2,187,925 $ 393,423 $ 254,020
=========== =========== ===========
45
46
Natural gas and oil prices have decreased since December 31, 2000.
Accordingly, the discounted future net cash flows shown above would 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,
---------------------------------------------
2000 1999 1998
----------- ----------- -----------
(IN THOUSANDS)
Gas and oil sales, net of production costs ............... $ (169,375) $ (76,052) $ (56,032)
Net changes in anticipated prices and production cost .... 1,535,058 32,745 (36,581)
Extensions and discoveries, less related costs ........... 251,410 31,796 33,651
Changes in estimated future development costs ............ 8,831 21,246 (2,652)
Previously estimated development costs incurred .......... 26,084 1,435 8,690
Net change in income taxes ............................... (652,306) (27,561) 3,336
Purchase of minerals in place ............................ 18,917 98,419 --
Sales of minerals in place ............................... (679) (1,207) (151)
Accretion of discount .................................... 39,343 25,402 30,081
Revision of quantity estimates ........................... 198,625 369 (10,716)
Changes in production rates and other .................... (113,712) 5,250 (13,083)
----------- ----------- -----------
Change in Standardized Measure ........................... $ 1,142,196 $ 111,842 $ (43,457)
=========== =========== ===========
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.
46
47
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)
2.2* -- Pre-Acquisition Agreement, dated December 13, 2000,
between Stellarton Energy Corporation and the Registrant
3.1 -- Certificate of Incorporation, as amended, of the
Registrant (Incorporated by reference to Exhibit 3.1 in
the Registrant's Form S-8 Report filed with the
Securities and Exchange Commission on December 6, 2000)
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)
4.2* -- First Amended and Restated Rights Agreement dated March
1, 2001 between the Registrant and EquiServe Trust
Company, N.A.
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,
47
48
10.6 -- and filed with the Securities and Exchange Commission on
November 13, 1998) 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 (Incorporated by reference to Exhibit 10.11 in
the Registrant's Form 10-K Report for the fiscal year
ended December 31, 1999, and filed with the Securities
and Exchange Commission on March 22, 2000)
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 (Incorporated by reference to Exhibit
10.13 in the Registrant's Form 10-K Report for the
fiscal year ended December 31, 1999, and filed with the
Securities and Exchange Commission on March 22, 2000)
10.14 -- Sauer Drilling Company Adoption Agreement and Prototype
401(k) Retirement Plan effective as of January 1, 1999
(Incorporated by reference to Exhibit 10.14 in the
Registrant's Form 10-K Report for the fiscal year ended
December 31, 1999, and filed with the Securities and
Exchange Commission on March 22, 2000)
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)
48
49
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)
10.19* -- Amended Schedule to Severance Agreement 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)
10.21 -- Credit Agreement dated June 30, 2000, among the
Registrant, The Chase Manhattan Bank and the other
lenders parties thereto (Incorporated by reference to
Exhibit 10.l in the registrant's Form 10-Q Report for
the quarterly period ended June 30, 2000, and filed with
the Securities and Exchange Commission on August 14,
2000).
10.22* -- Deferred Compensation Plan dated March 1, 2001.
21.1* -- Subsidiaries of the Registrant
23.1* -- Consent of Arthur Andersen LLP
23.3* -- Consent of Ryder Scott Company
- ----------
* Filed herewith
(4) Reports on Form 8-K:
Form 8-K Item 7. 2001 Financial Model Estimates filed on
January 9, 2001.
Form 8-K Item 2. Acquisition or Disposition of Assets filed on
January 26, 2001.
Form 8-K/A Item 7. Financial Statements of Business Acquired
filed on February 12, 2001.
49
50
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/ JAMES B. WALLACE
----------------------------------
James B. Wallace
Chairman of the Board of Directors
Date: March 13, 2001
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/ JAMES B. WALLACE Chairman of the Board March 13, 2001
- --------------------------------------
James B. Wallace
/s/ JAMES D. LIGHTNER President and Chief March 13, 2001
- -------------------------------------- Executive Officer
James D. Lightner
/s/ DANIEL G. BLANCHARD Executive Vice President, March 13, 2001
- -------------------------------------- Chief Financial Officer and
Daniel G. Blanchard Treasurer
/s/ RICHARD L. SATRE
- -------------------------------------- Controller March 13, 2001
Richard L. Satre
/s/ THOMAS C. BROWN Director March 13, 2001
- --------------------------------------
Thomas C. Brown
/s/ DAVID M. CARMICHAEL Director March 13, 2001
- --------------------------------------
David M. Carmichael
/s/ HENRY GROPPE Director March 13, 2001
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Henry Groppe
/s/ EDWARD W. LEBARON, JR. Director March 13, 2001
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Edward W. LeBaron, Jr.
/s/ ROBERT H. WHILDEN, JR. Director March 13, 2001
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Robert H. Whilden, Jr.
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TOM BROWN, INC.
EXHIBITS
TO
ANNUAL REPORT ON FORM 10-K
FOR THE PERIOD ENDED
DECEMBER 31, 2000
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------ -----------
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)
2.2* -- Pre-Acquisition Agreement, dated December 13, 2000,
between Stellarton Energy Corporation and the Registrant
3.1 -- Certificate of Incorporation, as amended, of the
Registrant (Incorporated by reference to Exhibit 3.1 in
the Registrant's Form S-8 Report filed with the
Securities and Exchange Commission on December 6, 2000)
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)
4.2* -- First Amended and Restated Rights Agreement dated March
1, 2001 between the Registrant and EquiServe Trust
Company, N.A.
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,
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10.6 -- and filed with the Securities and Exchange Commission on
November 13, 1998) 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 (Incorporated by reference to Exhibit 10.11 in
the Registrant's Form 10-K Report for the fiscal year
ended December 31, 1999, and filed with the Securities
and Exchange Commission on March 22, 2000)
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 (Incorporated by reference to Exhibit
10.13 in the Registrant's Form 10-K Report for the
fiscal year ended December 31, 1999, and filed with the
Securities and Exchange Commission on March 22, 2000)
10.14 -- Sauer Drilling Company Adoption Agreement and Prototype
401(k) Retirement Plan effective as of January 1, 1999
(Incorporated by reference to Exhibit 10.14 in the
Registrant's Form 10-K Report for the fiscal year ended
December 31, 1999, and filed with the Securities and
Exchange Commission on March 22, 2000)
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)
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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)
10.19* -- Amended Schedule to Severance Agreement 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)
10.21 -- Credit Agreement dated June 30, 2000, among the
Registrant, The Chase Manhattan Bank and the other
lenders parties thereto (Incorporated by reference to
Exhibit 10.l in the registrant's Form 10-Q Report for
the quarterly period ended June 30, 2000, and filed with
the Securities and Exchange Commission on August 14,
2000).
10.22* -- Deferred Compensation Plan dated March 1, 2001.
21.1* -- Subsidiaries of the Registrant
23.1* -- Consent of Arthur Andersen LLP
23.3* -- Consent of Ryder Scott Company
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* Filed herewith
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