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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
----------------------
(MARK ONE)
|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
[FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001
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 (I.R.S. Employer
of incorporation or organization) Identification No.)
555 SEVENTEENTH STREET
SUITE 1850
DENVER, COLORADO 80202
(Address of principal executive offices) (Zip Code)
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303-260-5000
(Registrant's telephone number, including area code)
Securities Registered Pursuant to Section 12(b) of the Act: None
Securities Registered Pursuant to Section 12(g) of the Act:
COMMON STOCK, $.10 PAR VALUE
CONVERTIBLE PREFERRED STOCK, $.10 PAR VALUE
(TITLE OF CLASS)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes |X| No | |
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. Yes | | No | |
The aggregate market value of the Registrant's Common Stock held by
non-affiliates (based upon the last sale price of $27.23 per share as quoted on
the NASDAQ National Market System) on March 11, 2002 was approximately
$1,066,275,700.
As of March 11, 2002, there were 39,158,124 shares of Common Stock
outstanding.
1
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's definitive proxy statement for the 2001 Annual
Meeting of Stockholders to be held on May 9, 2002 are incorporated by reference
into Part III.
TOM BROWN, INC.
FORM 10-K
CONTENTS
Page
----
PART I
Item 1. Business...................................................... 3
Item 2. Properties.................................................... 9
Item 3. Legal Proceedings............................................. 13
Item 4. Submission of Matters to a Vote of Security Holders........... 13
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters......................................... 13
Item 6. Selected Financial Data....................................... 15
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 16
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk........................................................ 22
Item 8. Financial Statements and Supplementary Data................... 24
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 51
PART III
Item 10. Directors and Executive Officers of the Registrant............ 51
Item 11. Executive Compensation........................................ 52
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 52
Item 13. Certain Relationships and Related Transactions................ 52
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K......................................................... 52
Signatures.................................................... 56
2
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 Seventeeth 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, the East Texas Basin and the Western Alberta area of Canada. 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 ("Stellarton"). This
transaction was completed on January 12, 2001.
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 in 2001 was an extension of this fundamental strategy.
The Company's year-end domestic acreage position was approximately
3,023,000 gross (1,929,000 net) acres (including options) located primarily in
the Wind River and Green River Basins of Wyoming, the Piceance Basin of
Colorado, the Paradox Basin of Colorado and Utah, and the Permian, Val Verde and
East Texas Basins of Texas where the Company can utilize its geological and
technical expertise and its control of operations for the further development
and expansion of these areas. Approximately 90% of the net acreage is
undeveloped.
The Company's year-end Canadian acreage position located in Western
Alberta was approximately 519,000 gross (351,000 net) acres. Approximately 60%
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 2001 over 2000 by 21% due
primarily to continued drilling success in its core areas and the acquisition of
reserves primarily associated with the Canadian Stellarton transaction. Year-end
proved reserves were 732 billion cubic feet equivalent ("Bcfe"),
3
compared to year-end 2000 reserves of 603 Bcfe. At December 31, 2001, the
Canadian reserve base (as adjusted for negative price revisions, extensions and
discoveries and performance adjustments subsequent to the January 2001
acquisition date) was 77 Bcfe. Since December 31, 1995, the Company has
increased proved reserves at a compounded annual growth rate of 25%, or from 188
Bcfe to 732 Bcfe.
Reserve replacement for 2001 was 294% from all sources and 191% from
extensions, discoveries and revisions only. Finding cost was $1.52 per Mcfe for
the year from all sources and a 3-year average finding cost of $1.09 per Mcfe.
The Company's reserve to production ratio was 9.6 years at year-end 2001
compared to 9.7 years at year-end 2000. In addition to increasing reserves, the
Company also increased its production 23% from 62.3 Bcfe in 2000 to 76.4 Bcfe in
2001.
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.
The Company also conducts gas gathering and processing activities in
the Rocky Mountain area. Initially, these functions were conducted through
Wildhorse Energy partners, LLC ("Wildhorse") which was owned 55% by Kinder
Morgan, Inc. ("KM") and 45% by the Company. In November 2000, these 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 these gathering and processing assets. In 2001,
TBIFS selectively sold many of the gathering and processing facilities received
in the Wildhorse asset distribution, retaining only those gathering systems
considered integral to the Company's gas and oil reserve base. The Company also
directly owns and operates several gas processing facilities adjacent to its
areas of operations.
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 domestic exploration and
development activities with approximately 75% of the Company's proved reserves
at December 31, 2001. The Company owns interests in 1,329 producing wells in
these basins that averaged net daily production of 137.9 Mmcfe for 2001. The
Company has approximately 1,685,000 gross (1,282,000 net) developed and
undeveloped acres in these basins, including option acreage of approximately
437,000 gross undeveloped (315,000 net) 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. Recognizing these restrictions,
various pipelines have constructed lines into this area which have added
capacity to move additional gas volumes.
PERMIAN AND VAL VERDE BASINS
The Permian and Val Verde Basins accounted for approximately 8% of
the Company's proved reserves at December 31, 2001. The Company's share of
production from these basins averaged 36 Mmcfepd of natural gas for 2001. The
Company holds between 30% to 50% working interests in approximately 33,000 gross
(16,000 net) acres and 90 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 288 wells and has
approximately 155,000 gross (83,000 net) developed and undeveloped acres in this
basin.
In the Permian Basin, the Company drilled a horizontal Montoya well
in 2001, at its Deep Valley prospect area, which tested non-commercial in the
Montoya formation but is still being evaluated in the Devonian formation. The
Company is continuing to explore at its Deep Valley prospect and plans to
re-enter an existing well and to drill a horizontal test of the Devonian
formation, which is stratigraphically above the Montoya formation in the first
quarter of 2002. In addition, the Company, as operator, along with its partners
completed shooting a 240 square mile 3-D seismic survey in 2001 and began
interpretation in early 2002.
4
EAST TEXAS BASIN
Together with Marathon Oil Corporation, the Company participates in
a continuing developmental drilling program in the Mimms Creek Field in
Freestone County, Texas. During 2001, eight wells were drilled under this
program, with the Company owning working interests ranging from 28% to 62.5%.
The Company has acquired approximately 80,000 net acres in the James Lime
(horizontal) Trend of the East Texas Basin, and in 2001, drilled seven wells in
this play. Five of the seven wells have been completed and connected to a sales
line, one well is waiting on a sales line and one well was temporarily
abandoned. This large regional play is in its early stages of development and
the Company is working to determine its potential based upon the initial
production rates and variable decline rates of the wells drilled to date.
CANADA
The Western Canada Sedimentary Basin accounted for approximately 11%
of the Company's proved reserves at December 31, 2001. The Company's share of
production from this basin averaged 23 Mmcfepd of natural gas for 2001. The
Company owns interests in 241 wells and has approximately 519,000 gross (351,000
net) developed and undeveloped acres in this area.
Business Developments
CURRENT DEVELOPMENTS IN THE GAS AND OIL BUSINESS
Acquisition of Stellarton Energy Corporation
Effective January 16, 2001, the Company completed the purchase of
100% of Stellarton Energy Corporation ("Stellarton"), in a transaction valued at
$95 million, which was 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 58.8 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, as of the date of the acquisition.
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 complimented the Company's undeveloped average position in the
Paradox Basin.
Included in the acquisition was the Lisbon Plant, a modern
sophisticated cyrogenic (60 million cubic feet per day inlet 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 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 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. "TBIFS" was formed as a
wholly-owned
5
subsidiary of Tom Brown, Inc. to administer the gathering and processing assets
received in this distribution.
In 2001, TBIFS selectively sold many of the gathering and processing
facilities received in the Wildhorse asset distribution. The principal asset
retained in this process was the Wind River gathering system in one of the
Company's core areas.
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. Subsequent to the acquisition, Sauer has acquired three
additional drilling rigs for approximately $4 million in total.
Markets
The Company's gas production has historically been sold under
month-to-month contracts with marketing companies. During 2001, 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 $9.98 per million British thermal unit ("Mmbtu") for
January 2001 to a low of $1.83 per Mmbtu for October 2001. The Company produced
approximately 59% of its gas production for 2001 from the Rocky Mountain area
where the price of gas varied as compared to NYMEX prices from $1.43 per Mmbtu
below NYMEX prices in July 2001 to $.02 above NYMEX prices in February 2001.
Production from the Company's new Canadian production base has also been subject
to price volatility. In 2001, gas production from the Canadian fields was
subject to gas pricing that ranged from $1.10 (USD) per Mmbtu above the February
2001 NYMEX price to a price that was $.98 (USD) per Mmbtu below the October 2001
NYMEX price.
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 weather,
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, 2001, 2000 and 1999.
YEARS ENDED DECEMBER 31,
-------------------------------
United States 2001 2000 1999
------- ------- -------
Production Volumes:
Natural Gas (MMcf) ..................... 57,163 51,199 40,514
Crude Oil (Mbbls) ...................... 723 773 909
Natural Gas Liquids (Mbbls) ............ 1,074 1,074 535
Net Average Daily Production Volumes:
Natural Gas (Mcf) ...................... 156,611 139,888 110,997
Crude Oil (Bbls) ....................... 1,979 2,113 2,491
Natural Gas Liquids (Mbbls) ............ 2,943 2,934 1,467
Average Sales Prices:
Natural Gas (per Mcf)(1) ............... $ 3.73 $ 3.46 $ 2.04
Crude Oil (per Bbl) .................... $ 22.64 $ 28.05 $ 16.98
Natural Gas Liquids (per Bbl) .......... $ 13.25 $ 16.77 $ 12.16
Average Production Cost (per Mcfe)(2) ...... $ .70 $ .76 $ .58
(1) Includes the effects of hedging.
(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.)
6
Year Ended December 31,
-----------------------
Canada 2001
------
Production Volumes:
Natural Gas (MMcf) ........................................ 6,661
Crude Oil (Mbbls) ......................................... 158
Natural Gas Liquids (Mbbls) ............................... 143
Net Average Daily Production Volumes:
Natural Gas (Mcf) ......................................... 18,247
Crude Oil (Bbls) .......................................... 432
Natural Gas Liquids (Mbbls) ............................... 392
Average Sales Prices:
Natural Gas (per Mcf) ..................................... $ 3.49
Crude Oil (per Bbl) ....................................... $25.11
Natural Gas Liquids (per Bbl) ............................. $20.23
Average Production Cost (per Mcfe) ............................ $ .62
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.
The executive officers of the Company on March 13, 2002 were as follows:
Name Age Position with Company Since
- ---- --- --------------------- -----
James B. Wallace.......................72 Chairman of the Board 2001
James D. Lightner......................49 President, Chief Executive Officer 1999
and Director
Thomas W. Dyk..........................48 Executive Vice President and Chief 1998
Operating Officer
Peter R. Scherer.......................45 Executive Vice President 1982
Daniel G. Blanchard....................41 Executive Vice President, Chief Financial 1999
Officer and Treasurer
Rodney G. Mellott......................44 Vice President - Land and Business 1999
Development
Bruce R. DeBoer........................49 Vice President, General Counsel and 1997
Secretary
Doug R. Harris.........................47 Vice President - Operations 2001
Each executive officer is elected annually by the Company's Board of
Directors to serve at the Board's discretion.
7
Employees
At December 31, 2001, the Company had 546 employees of which 211
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 - United States
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.
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.
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.
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.
8
Regulation - Canada
REGULATION OF GAS AND OIL PRODUCTION AND PRICE CONTROLS
The oil and natural gas industry in Canada is subject to extensive
controls and regulations imposed by various levels of government. It is not
expected that any of these controls or regulations will affect our operations in
a manner materially different than they would affect other oil and gas companies
of similar size.
In Canada, oil and gas exports are subject to regulation by the
National Energy Board (NEB), an independent federal regulatory agency. The
Company does not, at present, export oil or gas under the terms of these
regulations, but may be affected if regulations imposed by the NEB act to
restrict the sales of gas and oil by other companies. Exports are also subject
to the North American Free Trade Agreement (NAFTA) which became effective on
January 1, 1994. NAFTA carries forward most of the material energy terms
contained in the Canada-U.S. Free Trade Agreement. In the context of energy
resources, Canada continues to remain free to determine whether exports to the
United States or Mexico will be allowed provided that any export restrictions do
not: (i) reduce the proportion of energy resource exported relative to domestic
use (based upon the proportion prevailing in the most recent 36-month period),
(ii) impose an export price higher than the domestic price, and (iii) disrupt
normal channels of supply. All three countries are prohibited from imposing
minimum export or import price requirements. NAFTA contemplates clearer
disciplines on regulators to ensure fair implementation of any regulatory
changes and to minimize disruption of contractual arrangements, which is
important for Canadian natural gas exports.
The provincial government of Alberta also regulates the volume of
natural gas which may be removed from the province for consumption elsewhere
based on such factors as reserve availability, transportation arrangements and
market considerations.
In addition to federal regulation, each province has legislation and
regulations which govern land tenure, royalties, production rates, environmental
protection and other matters. The royalty regime on Crown lands is a significant
factor in the profitability of oil and natural gas production. Royalties payable
on production from lands other than Crown lands are determined by negotiations
between the mineral owner and the lessee. Crown royalties are determined by
government regulation and are generally calculated as a percentage of the value
of the gross production, and the rate of royalties payable generally depends in
part on prescribed reference prices, well productivity, geographical location,
field discovery date and the type or quality of the petroleum product produced.
From time to time the governments of Canada and Alberta have
established incentive programs which have included royalty rate deductions,
royalty holidays and tax credits for the purpose of encouraging oil and natural
gas exploration or enhanced recovery projects. At present, few of these programs
are currently in effect.
In Alberta, certain producers of oil or natural gas are currently
entitled to a credit against the royalties to the Crown by virtue of the ARTC
(Alberta royalty tax credit) program. The credit is determined by applying a
specified rate to a maximum of $2 million CDN of Alberta Crown royalties payable
for each producer or associated group of producers. The specified rate is a
function of the Royalty Tax Credit reference price (RTCRP) which is set
quarterly by the Alberta Department of Energy and ranges from 25% to 75%,
depending on oil and gas par prices for the previous calendar quarter. The
provincial government of Alberta has proposed changes to the ARTC program which
have not been finalized.
ENVIRONMENTAL REGULATION
In Canada, the oil and natural gas industry is currently subject to
environmental regulation pursuant to provincial and federal legislation.
Environmental legislation provides for restrictions and prohibitions on releases
or emissions of various substances produced or utilized in association with
certain oil and gas industry operations. In addition, legislation requires that
well and facility sites be abandoned and reclaimed to the satisfaction of
provincial authorities.
In Alberta, environmental compliance has been governed by the
Alberta Environmental Protection and Enhancement Act ("AEPEA") since September
1, 1993. In addition, AEPEA also imposes certain environmental responsibilities
on oil and natural gas operators in Alberta and in certain instances also
imposes penalties for violations.
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
9
lease 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.
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, 2001.
Excluded from the table are approximately 437,000 gross (315,000 net) acres in
Wyoming under gas and oil option agreements acquired from certain Indian tribes.
DEVELOPED UNDEVELOPED
--------------------------- ------------------------------
GROSS NET GROSS NET
----------- ----------- -------------- ------------
Colorado.................................... 101,600 82,319 604,683 481,267
Louisiana................................... 10,045 3,892 6,152 1,649
Michigan.................................... -- -- 303 121
Montana..................................... 4,678 718 158,307 26,443
Nebraska.................................... -- -- 31,455 30,861
New Mexico.................................. 15,417 3,952 2,440 2,096
North Dakota................................ 3,720 105 5,880 112
Texas....................................... 107,167 37,906 315,675 197,148
Utah........................................ 6,799 5,521 101,589 94,912
West Virginia............................... 3,852 1,240 153,206 76,920
Wyoming..................................... 138,234 63,513 815,165 503,577
Canada...................................... 258,200 139,100 260,500 211,800
Other....................................... -- -- 10 2
------- ------- --------- ---------
Total.......................... 649,712 338,266 2,455,365 1,626,908
======= ======= ========= =========
"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, 2001
and 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. 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.
10
Productive Wells
The following table sets forth the gross and net productive gas and
oil wells in which the Company owned an interest at December 31, 2001.
PRODUCTIVE WELLS
---------------------------------------------------------
Gross Net
----------------------- -------------------------
Gas Oil Gas Oil
---------- ------- --------- ---------
Colorado.................................... 695 4 342.99 3.13
Louisiana................................... 38 30 10.23 8.67
New Mexico.................................. 26 26 5.91 6.04
Utah........................................ 13 19 12.23 18.91
Texas....................................... 164 278 67.34 95.79
West Virginia............................... 131 -- 32.95 --
Wyoming..................................... 731 267 292.44 46.67
Canada...................................... 151 90 74.00 24.40
Other....................................... 21 6 1.47 .80
----- --- ------ ------
Total.......................... 1,970 720 839.56 204.41
===== === ====== ======
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.
11
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. The
relative net percentage of the wells drilled by type and category is also
disclosed.
UNITED STATES CANADA
----------------------------------- -----------------------------------
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------------
2001 2001
------------------------------------- -----------------------------------
TYPE OF WELL Gross Net Net% Gross Net Net%
------------ -------- -------- -------- -------- -------- -------
Exploratory
Gas.................... 7 6.6 49 -- -- --
Oil.................... -- -- -- -- -- --
Dry.................... 12 6.7 51 4 3.6 100
-- ---- --- -- --- ---
19 13.3 100 4 3.6 100
Development
Gas.................... 139 98.1 97 22 16.0 71
Oil.................... -- -- -- 1 .5 2
Dry.................... 7 3.3 3 8 6.1 27
--- ----- --- -- ---- ---
146 101.4 100 31 22.6 100
Total..................... 165 114.7 35 26.1
=== ===== == ====
UNITED STATES
-----------------------------------------------------------------------------
YEARS ENDED DECEMBER 31,
-----------------------------------------------------------------------------
2000 1999
------------------------------------ ------------------------------------
TYPE OF WELL Gross Net Net% Gross Net Net%
------------
-------- -------- -------- -------- -------- --------
Exploratory
Gas.................. -- -- -- 2 .8 20
Oil.................. -- -- -- -- -- --
Dry.................. 3 2.3 100 4 3.2 80
-- --- --- -- --- ---
3 2.3 100 6 4.0 100
Development
Gas.................. 63 33.7 93 37 16.3 99
Oil.................. 1 .2 1 1 0.2 1
Dry.................. 4 2.3 6 -- -- --
-- ---- --- -- ---- ---
68 36.2 100 38 16.5 100
Total................... 71 38.5 44 20.5
== ==== == ====
At December 31, 2001, 14 gross (10 net) development wells and 2
gross (.9 net) exploration wells were in various stages of drilling and
completion in Texas, Colorado, and Wyoming, while 4 gross (2.6 net) development
wells were in various stages of drilling and completion in Canada.
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 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 also leases office facilities in Calgary, Alberta. The
lease covers approximately 14,600 square feet for a term of five years and
expires August 31, 2004.
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.
12
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, 2001.
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, 2000.................................... 18.38 12.00
June 30, 2000..................................... 23.06 17.75
September 30, 2000................................ 24.50 17.00
December 31, 2000................................. 36.00 20.44
March 31, 2001.................................... 35.25 29.56
June 30, 2001..................................... 32.99 23.34
September 30, 2001................................ 27.45 20.16
December 31, 2001................................. 27.46 20.20
On March 11, 2002 the last sale price of the Company's Common Stock,
as reported by the NASDAQ National Market System, was $27.23 per share.
The transfer agent for the Company's Common Stock is EquiServe Trust
Company, N.A., Canton, Massachusetts.
On December 31, 2001, the outstanding shares of the Company's Common
Stock (39,127,649 shares) were held by approximately 1,843 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.
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
13
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.
14
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
Stellarton Acquisition in January 2001, the Unocal Acquisition in July 1999, the
Genesis Acquisition in October 1997, the Presidio Acquisition in December 1996,
and the KNPC Acquisition in January 1996. (See Note 3 to Notes to Consolidated
Financial Statements of the Company included elsewhere herein.)
Years Ended December 31,
-------------------------------------------------------------
2001 2000 1999 1998 1997
--------- --------- --------- --------- ---------
(In thousands, except per share amounts)
Revenues .......................... $ 326,324 $ 253,910 $ 123,411 $ 89,939 $ 93,175
========= ========= ========= ========= =========
Net income (loss) attributable to
common stock .................. 69,503 65,703 5,007 (45,233) 6,860
========= ========= ========= ========= =========
Weighted average number of common
shares outstanding
Basic ......................... 38,943 36,664 32,228 29,251 25,110
========= ========= ========= ========= =========
Diluted ....................... 40,227 37,897 32,466 29,251 26,407
========= ========= ========= ========= =========
Net income (loss) per common share
Basic ......................... 1.78 1.79 .16 (1.55) .27
========= ========= ========= ========= =========
Diluted ....................... 1.73 1.76 .15 (1.55) .26
========= ========= ========= ========= =========
Total assets ...................... 844,975 629,535 536,299 441,882 450,926
========= ========= ========= ========= =========
Long-term debt, net of current
maturities .................... 120,570 54,000 81,000 55,000 23,000
========= ========= ========= ========= =========
Other Financial Data:
EBITDAX (1) ................... 227,796 177,643 74,438 49,348 69,716
Net cash provided by operating
activities before changes in
working capital (1) ........ 192,712 159,956 59,821 34,404 59,652
Net cash provided by operating
activities ................. 207,900 132,958 38,857 60,100 47,600
Net cash used in investing
activities ................. (276,987) (117,738) (54,999) (89,634) (86,672)
Net cash provided by (used in)
financing activities ....... 66,975 (10,196) 25,982 25,667 25,105
(1) 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. EBITDAX for 2001 excludes the
cumulative effect of the change in accounting principle.
15
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,
-----------------------------------------------
2001 2000 1999 1998 1997
------- ------- ------- ------- -------
Volumes sold:
Gas (Mmcf) ................. 63,824 51,199 40,514 35,887 31,842
Oil (MBbls) ................ 881 773 910 1,027 1,159
Natural Gas Liquids (MBbls) 1,217 1,074 535 -- --
Proved reserves at period end:
Gas (Mmcf) ................. 641,579 535,373 445,933 372,022 347,104
Oil (MBbls) ................ 6,647 6,116 6,735 5,682 7,227
Natural Gas Liquids (MBbls) 8,360 5,077 6,266 -- --
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Critical Accounting Policies and Estimates
The discussion and analysis of the Company's financial condition and
results of operations was based upon the consolidated financial statements,
which have been prepared in accordance with accounting principles generally
accepted in the United States. The preparation of these financial statements
requires us to make estimates and judgments that affect the reported amounts of
assets, liabilities, revenues and expenses. Our significant accounting policies
are described in Note 2 to our consolidated financial statements. In response to
SEC Release No. 33-8040, "Cautionary Advise Regarding Disclosure About Critical
Accounting Policies," we have identified certain of these policies as being of
particular importance to the portrayal of our financial position and results of
operations and which require the application of significant judgment by
management. We analyze our estimates, including those related to oil and gas
revenues, bad debts, oil and gas properties, marketable securities, income
taxes, derivatives, contingencies and litigation, and base our estimates on
historical experience and various other assumptions that we believe to be
reasonable under the circumstances. Actual results may differ from these
estimates under different assumptions or conditions. We believe the following
critical accounting policies affect our more significant judgments and estimates
used in the preparation of the Company's financial statements:
SUCCESSFUL EFFORTS METHOD OF ACCOUNTING
The Company accounts for its natural gas and crude oil exploration
and development activities utilizing the successful efforts method of
accounting. Under this 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 costs, 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.
The application of the successful efforts method of accounting
requires managerial judgment to determine the proper classification of wells
designated as developmental or exploratory which will ultimately determine the
proper accounting treatment of the costs incurred. The results from a drilling
operation can take considerable time to analyze and the determination that
commercial reserves have been discovered requires both judgment and industry
experience. Wells may be completed that are assumed to be productive and
actually deliver gas and oil in quantities insufficient to be economic, which
may result in the abandonment of the wells at a later date. Wells are drilled
that have targeted geologic structures that are both developmental and
exploratory in nature and an allocation of costs is required to properly account
for the results. Delineation seismic incurred to select development locations
within an oil and gas field is typically considered a development cost and
capitalized but often these seismic programs extend beyond the reserve area
considered proved and management must estimate the portion of the seismic costs
to expense. The evaluation of gas and oil leasehold acquisition costs requires
managerial judgment to estimate the fair value of these costs with reference to
drilling activity in a given area. Drilling activities in an area by other
companies may also effectively condemn leasehold positions.
The successful efforts method of accounting can have a significant
impact on the operational results reported when the Company is entering a new
exploratory area in hopes of finding a gas and oil field that will be the focus
of future development drilling activity. The initial exploratory wells may
16
be unsuccessful and will be expensed. Seismic costs can be substantial which
will result in additional exploration expenses when incurred.
RESERVE ESTIMATES
The Company's estimates of gas and oil reserves, by necessity, are
projections based on geologic and engineering data, and there are uncertainties
inherent in the interpretation of such data as well as the projection of future
rates of production and the timing of development expenditures. Reserve
engineering is a subjective process of estimating underground accumulations of
gas and oil that are difficult to measure. The accuracy of any reserve estimate
is a function of the quality of available data, engineering and geological
interpretation and judgment. Estimates of economically recoverable gas and oil
reserves and future net cash flows necessarily depend upon a number of variable
factors and assumptions, such as historical production from the area compared
with production from other producing areas, the assumed effects of regulations
by governmental agencies and assumptions governing future gas and oil prices,
future operating costs, severance taxes, development costs and workover gas
costs, all of which may in fact vary considerably from actual results. The
future drilling costs associated with reserves assigned to proved undeveloped
locations may ultimately increase to an extent that these reserves may be later
determined to be uneconomic. For these reasons, estimates of the economically
recoverable quantities of gas and oil attributable to any particular group of
properties, classifications of such reserves based on risk of recovery, and
estimates of the future net cash flows expected therefrom may vary
substantially. Any significant variance in the assumptions could materially
affect the estimated quantity and value of the reserves, which could affect the
carrying value of the Company's gas and oil properties and/or the rate of
depletion of the gas and oil properties. Actual production, revenues and
expenditures with respect to the Company's reserves will likely vary from
estimates, and such variances may be material.
IMPAIRMENT OF GAS AND OIL PROPERTIES
The Company reviews its gas and oil properties for impairment whenever
events and circumstances indicate a decline in the recoverability of their
carrying value. The Company estimates the expected future cash flows of its gas
and oil properties and compares such future cash flows to the carrying amount of
the gas and oil properties to determine if the carrying amount is recoverable.
If the carrying amount exceeds the estimated undiscounted future cash flows, the
Company will adjust the carrying amount of the gas and oil properties to their
fair value. The factors used to determine fair value include, but are not
limited to, estimates of proved reserves, future commodity pricing, future
production estimates, anticipated capital expenditures, and a discount rate
commensurate with the risk associated with realizing the expected cash flows
projected. There were no impairments of gas and oil properties in 2001, 2000 or
1999.
Given the complexities associated with gas and oil reserve estimates
and the history of price volatility in the gas and oil markets, events may arise
that would require the Company to record an impairment of the recorded book
values associated with gas and oil properties. In 1998, the Company recognized
an impairment of $51.3 million primarily as a result of the market prices in
effect at that time and there can be no assurance that impairments will not be
required in the future.
Results of Operations
The Company's results of operations were favorably impacted in 2001,
2000 and 1999 due to the acquisition of Stellarton in January 2001 and the
mid-1999 acquisition of properties and a gas processing plant from Unocal. These
acquisitions, continued successful drilling results and increased cash flows
which resulted from higher production and commodity prices in 2001 and 2000
contributed significantly to the operating results for these periods.
REVENUES
During 2001, revenues from gas, oil and natural gas liquids
production increased 26% to $274.0 million, as compared to $217.0 million in
2000. This increase was the result of (i) an increase in average gas prices
received by the Company from $3.46 per Mcf in 2000 to $3.71 per Mcf in 2001,
which increased revenues $16.0 million, (ii) a decrease in average oil and
natural gas liquids prices received from $21.49 to $17.86 which decreased
revenues $7.6 million, (iii) gas sales volumes increased by 25% to 63.8 Bcf
which increased revenues by $43.7 million, and (iv) an increase in oil and
natural gas liquids sales volumes of 14% to 2.1 million barrels, which increased
revenues by $4.9 million.
Revenues in 2001 were also impacted by cash gains realized from
hedging activities. The NYMEX collar and swap transactions considered effective
hedges and settled in 2001, resulted in cash gains of $15.9 million, which were
included in gas and oil sales. At December 31, 2001, the Company had no open
hedge or derivative positions. There was no material hedging activity in 1999 or
2000.
The revenues contributed by the Stellarton transaction for the
period subsequent to the closing date of January 12, 2001 were $30.1 million.
17
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.
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,
-------------------------------
2001 2000 1999
-------- -------- ---------
(IN THOUSANDS)
Revenues:
Natural gas sales ........................ $236,551 $177,267 $ 82,479
Crude oil sales .......................... 20,350 21,686 15,443
Natural gas liquids ...................... 17,130 18,015 6,509
Gathering and processing ................. 23,245 18,283 11,968
Marketing and trading, net ............... 1,891 5,841 (786)
Drilling ................................. 14,828 11,472 5,645
Gain on sale of property ................. 10,078 -- --
Interest income and other ................ 2,251 1,346 2,153
-------- -------- ---------
Total revenues ........................... $326,324 $253,910 $ 123,411
======== ======== =========
Net income attributable to common stock ...... $ 69,503 $ 65,703 $ 5,007
======== ======== =========
YEARS ENDED DECEMBER 31,
-------------------------------
2001 2000 1999
-------- -------- ---------
Natural gas production sold (Mmcf) ........... 63,824 51,199 40,514
Crude oil production (Mbbls) ................. 881 773 910
Natural gas liquid production (Mbbls) ........ 1,217 1,074 535
Average natural gas sales price ($/Mcf) ...... $ 3.71 $ 3.46 $ 2.04
Average crude oil sales price ($/Bbl) ........ $ 23.09 $ 28.05 $ 16.98
Average natural gas liquid sales price ($/Bbl) $ 14.07 $ 16.77 $ 12.16
Gathering and processing revenue increase 27% to $23.2 million as
compared to $18.3 million in 2000. In 2000, revenue increased 53% to $18.3
million, as compared to $12.0 million in 1999. In November 2000, certain
gathering and processing assets were distributed to the Company from Wildhorse
Energy Partners, LLC ("Wildhorse"). Incremental revenues were recognized in 2001
as a result of the 100% ownership of these gathering and processing assets which
previously were 45% owned by the Company through the Wildhorse partnership. A
number of non-strategic gathering and processing assets were sold throughout
2001. Gathering and processing revenue will be impacted in 2002 as a result of
these dispositions. TBI Field Services, Inc. ("TBIFS") was formed as a
wholly-owned subsidiary of Tom Brown, Inc. to administer the gathering and
processing assets. Incremental volumes gathered by TBIFS from the Wind River
Basin where the Company has significant production base also contributed to the
increase in revenues.
Net marketing and trading income increased from a net loss in 1999
to a profitable gross margin of $5.8 million in 2000 and $1.9 million in 2001.
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. In 2000, the Company benefited
from certain term and spot natural gas sales at more favorable rates than were
available in the 2001 market.
Drilling revenue associated with the Company's wholly-owned
subsidiary, Sauer, increased 29% in 2001 to $14.8 million and 103% to $11.5
million in 2000 due to higher rig utilization rates and increased day rates
resulting from the general increase in activity within the oil and gas industry
in 2001 and 2000.
18
COSTS AND EXPENSES
Expenses related to gas and oil production increased 26% from 2000
to 2001 due primarily to the Stellarton Acquisition and increased production
levels in 2001. On an Mcfe basis, gas and oil production costs remained
relatively flat at $.42 in 2001 and $.41 in 2000.
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.
Taxes on gas and oil production decreased by 5% (or $1.1 million) in
2001 despite a 26% (or $57 million) increase in revenue from gas, oil and
natural gas liquids for 2001. This relationship resulted from the inclusion of
$30.1 million of Canadian revenues in the 2001 results which are not subject to
severance and other taxes typically incurred in the United States. Additionally,
$15.9 million realized on the natural gas hedge transactions was included in gas
and oil sales in 2001 which is not subject to production related taxes. The
Company also obtained a refund in 2001 of a portion of the production taxes paid
in prior years' which reduced the expenses reported.
Taxes on gas and oil production increased 123% in 2000 directly
related to the increase in gas, oil and natural gas liquids sales in these
periods. The taxes for 1999 and 2000 remained relatively constant as a
percentage of sales.
Depreciation, depletion and amortization increased $24.0 million in
2001 as compared to 2000. Approximately $14.1 million of this increase was
associated with the depletion recorded on the Stellarton assets acquired in
January 2001. The production increase of 9% on a Mcfe basis on the domestic
properties for 2001 also increased depreciation, depletion and amortization. To
a lessor extent, the increased cost associated with finding new proved reserves
increased the depletion rate in 2001. Depreciation, depletion and amortization
increased $6.2 million in 2000, as compared to 1999. The increase was primarily
due to increased production, partially offset by a 9% increase in reserve
quantities 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 operating and
maintaining the gathering and processing systems. This expense increased in 2001
and the last month of 2000, due to the 100% ownership of the gathering
operations after the Wildhorse distribution, 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
$34.2 million, $11.0 million and $10.0 million for the years 2001, 2000 and
1999, respectively. The Company's increased exploration efforts in 2001 resulted
in increased dryhole costs and seismic related expenses. Capital expenditures of
$358.1 million were incurred in 2001 which included $95 million associated with
the Stellarton acquisition. The 2001 exploration, development and land related
expenditures were $242 million, an increase of 121% in comparison to 2000. In
1999, the Unocal acquisition was completed at a cost of $60.9 million and the
exploration, development and land related expenditures were $47.4 million.
General and administrative expenses have increased from year to year
as a result of the Company's increased level of operations. On an Mcfe basis,
general and administrative expenses were $.30, $.19, and $.19 for the years
2001, 2000 and 1999, respectively. Included in the expenses for 2001 was a $5.3
million ($.07 per Mcfe) pre-tax charge recorded in the first quarter of 2001
associated with the retirement of Donald L. Evans, previously Tom Brown, Inc.'s
Chairman and CEO. Mr. Evans received a $1.5 million retirement payment and the
Company recognized a $3.8 million non-cash charge in conjunction with the
acceleration of Mr. Evans' stock options. General and administrative expenses
related to Stellarton contributed $2.5 million ($.03 per Mcfe) to the increase
from 2000. Expenses also increased due to the addition of personnel necessary to
accomplish the increase in the capital expenditure programs.
Interest expense increased $1.4 million in 2001 due to the increase
in debt associated with financing the Stellarton transaction. The increased debt
levels in 2001 resulting from this transaction benefited from the general
reduction in interest rates during this period. The Company's effective interest
rate under its credit facility was 7.9% at December 31, 2000 and 4.1% at
December 31, 2001. Interest expense increased $.4 million in 2000 to $6.0
million as compared to $5.6 million in 1999 due to an increase in interest rates
in 2000.
The Company recorded income tax provisions of $38.1 million, $39.8
million and $4.3 million in 2001, 2000, and 1999, respectively, resulting in
effective tax rates of 36.1%, 37.4% and 38.9%, respectively. At December 31,
2001, the Company has a net operating loss carryforward available for U.S.
Federal tax purposes of $18.7 million and a net operating loss carryforward
available to reduce future Canadian federal income taxes of $700,000 ($1,084,000
CDN). Additionally, statutory depletion carryforwards of approximately $6.2
million and $5.2 million of alternative minimum tax credit carryforwards are
available in the U.S. to offset future taxes. Based upon the operating results
for 2001 and the present economic environment for the oil and gas industry, the
Company believes that it will generate sufficient taxable income to utilize
these carryforwards.
19
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. The Company does not conduct its business through special
purpose entities or have any exposure to off-balance sheet financing
arrangements.
CAPITAL AND EXPLORATION EXPENDITURES
The Company's capital and exploration expenditures and sources of
financing for the years ended December 31, 2001, 2000 and 1999 are as follows:
2001 2000 1999
------- ------- -------
(IN MILLIONS)
CAPITAL AND EXPLORATION EXPENDITURES:
ACQUISITIONS:
Stellarton ........................................... $ 95.0 $ -- $ --
Sauer Drilling Company ............................... 5.2 2.7 1.4
Unocal ............................................... -- -- 60.9
Other Rocky Mountain Assets .......................... 3.3 17.1 8.2
Other ................................................ -- -- 2.5
Exploration costs ........................................ 56.0 18.4 12.0
Development costs ........................................ 163.2 74.4 33.2
Acreage .................................................. 22.6 16.8 2.5
Gas gathering and processing ............................. 9.3 16.3 2.7
Other .................................................... 3.5 4.8 1.7
------- ------- -------
$ 358.1 $ 150.5 $ 125.1
======= ======= =======
FINANCING SOURCES:
Common stock issued ...................................... $ 11.2 $ 17.7 $ 65.2
Net long term bank debt .................................. 55.8 (27.0) 26.0
Debt assumed on Stellarton transaction ................... 16.8 -- --
Advances from gas purchasers ............................. -- -- (24.5)
Proceeds from sale of assets ............................. 52.4 9.7 2.6
Cash flow from operations before changes in
working capital ...................................... 192.7 160.0 59.8
Working capital and other ................................ 29.2 (9.9) (4.0)
------- ------- -------
$ 358.1 $ 150.5 $ 125.1
======= ======= =======
The Company anticipates capital and exploration expenditures between
$115 to $125 million in 2002, $104 to $113 million allocated to exploration and
development activity. The timing of most of the Company's capital expenditures
is discretionary and there are no material long-term commitments associated with
the Company's capital expenditure plans. Consequently, the Company is able to
adjust the level of its capital expenditures as 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 $207.9 million for 2001 as compared to $133.0 million and
$38.9 million in 2000 and 1999, respectively. Net cash flow in 1999 was impacted
by 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.
PROPERTY SALES
In 2001, $52.4 million in cash proceeds were derived from property
sales. In May 2001, the Company sold its interest in oil and gas properties
located in Oklahoma. These properties had a net book basis of $14.4 million.
This transaction resulted in a gain of $10.l million with net cash proceeds of
$24.5 million. Cash proceeds of $24 million were also realized in conjunction
with several sales transactions in 2001 associated with the disposition of
gathering and processing facilities received in the Wildhorse distribution in
November 2000. As the systems sold were non-strategic to the Company's
operations and these divestitures were anticipated as part of the Wildhorse
integration process, the proceeds derived on these transactions were recorded as
a reduction to the investment in the gathering assets.
20
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.
DEBT
CONTRACTUAL OBLIGATIONS
In addition to the bank credit facility discussed in the following
note, the Company had various other contractual obligations as of December 31,
2001. The following table lists the Company's significant liabilities at
December 31, 2001 including the credit facility:
PAYMENTS DUE BY PERIOD
------------------------------------------------------------------
CONTRACTUAL OBLIGATIONS LESS THAN 1 YEAR 2-3 YEARS 4-5 YEARS AFTER 5 YEARS TOTAL
- ----------------------- ---------------- --------- --------- ------------- --------
(IN THOUSANDS)
Bank credit facility $ -- $ 25,570 $ 95,000 $ -- $120,570
Operating leases 1,502 1,544 -- -- 3,046
Transportation
commitments 5,176 6,706 2,425 596 14,903
Processing
commitment 2,268 4,536 4,536 11,340 22,680
Drilling
obligation 4,841 10,372 -- -- 15,213
-------- -------- -------- -------- --------
Total contractual cash
obligations $ 13,787 $ 48,728 $101,961 $ 11,936 $176,412
======== ======== ======== ======== ========
The Company leases its corporate offices in Denver, Colorado under
the terms of an operating lease, which expires in January 2004. Yearly payments
under the lease are approximately $900,000 net of sublease income. The office
lease in Midland, Texas represents a commitment of $215,000 per year through
December 2003 and the office lease in Calgary, Alberta expires in August 2004 at
a rate of $152,000 per year. The remaining operating lease commitments represent
equipment leases, which expire during 2002 through 2004.
The Company has entered into various firm transportation commitments
for approximately 60 MMcf of gross gas sales per day as of December 31, 2001.
The majority of these contracts expire in 2002 and 2003.
At December 31, 2001, the Company had entered into an agreement with
a third party to process its gas production from the White River Dome coal bed
methane project in the Piceance Basin. Under the terms of this agreement, the
Company is obligated to pay the third party $189,000 per month over the ten year
term to cover the fixed operating costs of the plant and provide for a recovery
of the plant investment to the third party. The Company is also obligated to
reimburse the third party for certain variable expenses associated with the
volumes processed through the plant and for compression made available to the
Company. Under certain circumstances, the Company has the right but not the
obligation to purchase the processing facility from the third party during the
term of this agreement.
To assure the availability of a drilling rig in conjunction with an
exploration program in West Texas, the Company entered into a two-year
commitment with a drilling contractor in 2001. The rig became available on March
1, 2002 after which a 90-day period is allowed under the terms of this agreement
to mobilize the rig and commence the two-year drilling obligation. Under the
terms of this arrangement, the Company is required to pay a daywork rate of
$20,100/day during drilling operations, $16,700/day for rig moves and a special
standby rate of $6,000/day during the initial 90-day commencement period.
BANK CREDIT FACILITY
On June 30, 2000, the Company entered into a new $125 million credit
facility (the "New Credit Facility") that was to mature in June 2003. Under the
terms of the New Credit Facility, the borrowing base was established at $225
million.
On March 20, 2001, as part of the final financing of the Stellarton
acquisition, the Company repaid and cancelled its previous $125 million
revolving credit facility and entered into a new $225 million credit facility
(the "Global Credit Facility"). The Global Credit Facility is comprised of: a
$75 million line of credit in the U.S. and a $55 million line of credit in
Canada which both mature in March 2004, and a $95 million five-year term loan in
Canada. The borrowing base under the Global Credit Facility was set at $300
million. The Global Credit Facility allows the lenders one scheduled
redetermination of the borrowing base each December. In addition, the lenders
may elect to require one unscheduled redetermination in the event the borrowing
base utilization exceeds 50% of the borrowing base at any time for a period of
15 consecutive business days. At December 31, 2001, the Company had borrowings
outstanding under the Global Credit Facility totaling $120.6 million or 40% of
the borrowing base at an average interest rate of 4. 1%. The amount available
for borrowing under the Global Credit Facility at December 31, 2001 was $104.4
million.
Borrowings under the Global Credit Facility are unsecured and bear
interest, at the election of the Company, at a rate equal to (i) the greater of
the global administrative agents prime rate or the federal funds effective rate
plus an applicable margin, (ii) adjusted LIBOR for Eurodollar loans plus
applicable margin, or (iii) Bankers' Acceptances plus applicable margin for
Canadian dollar loans. Interest on amounts outstanding under the Global Credit
Facility is due on the last day of each quarter for prime based loans, and in
the case of Eurodollar loans with an interest period of more than three months,
interest is due at the end of each three month interval.
The Global Credit Facility contains certain financial covenants and
other restrictions similar to the limitations associated with the cancelled
credit facility. The financial covenants of the Global Credit Facility require
the Company to maintain a minimum consolidated tangible net worth of not less
than $350 million (adjusted upward by 50% of quarterly net income and 50% of the
net cash proceeds of any stock offering) and the Company will not permit its
ratio of (i) indebtedness to (ii) earnings before interest expense, State and
Federal taxes and depreciation, depletion and amortization expense and
exploration expense to be more than 3.0 to 1.0 as calculated at the end of each
fiscal quarter. The Company was in compliance with all covenants during 2001 and
at December 31, 2001.
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 gas and oil
production has been presold at contractually specified prices. During 2001, the
average prices received for gas and oil by the Company were $3.71 per Mcf and
$17.86 per barrel, respectively, as compared to $3.46 Mcf and $21.49 per barrel
in 2000 and $2.04 per Mcf and $15.20 per barrel in 1999.
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 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 collar
arrangements (put and call options) to hedge approximately 40% of the Company's
expected 2001 U.S. gas production. These positions were open as of January 1,
2001 when the Company adopted SFAS 133 and SFAS 138. 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 Loss 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. As of December 31, 2001, the Company had
no outstanding cash flow hedges. The Company received cash settlements of $15.4
million in 2001, which were recognized as increases in gas and oil sales.
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 did not qualify for hedge accounting.
Accordingly, upon adoption of SFAS 133, these basis swaps resulted 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 asset of $3.2 million. A $.9 million gain was
recognized in conjunction with the change in the value of these contracts in the
year ended December 31, 2001. Cash receipts of $4.1 million were received during
this period. No basis swaps were outstanding at December 31, 2001.
In August 2001, the Company entered into NYMEX based swaps for the
September and October 2001 contract periods. Basis swaps were purchased on these
quantities to correlate the volumes back to markets where the Company actually
delivers gas. Cash settlements of $2.0 million were received on these contracts
which increased gas and oil sales.
In October 2001, the Company entered into NYMEX based swaps for the
November 2001 contract period. Basis swaps were purchased on these quantities to
correlate the volumes back to markets where the Company actually delivers gas. A
cash settlement of $1.5 million was paid on the contracts which decreased gas
and oil sales.
At December 31, 2001, there were no collars or other forms of
hedging transactions in place.
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.
21
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 were 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. The Company
does not conduct its business through any special purpose entities or have any
exposure to off-balance sheet financing arrangements.
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 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.
Interest Rate Risk
At December 31, 2001, the Company had $120.6 million outstanding
under the Global Credit Facility at an average interest rate of 4.1%. Borrowings
under the Global Credit Facility bear interest, at the election of the Company,
at (i) the greater of the global administrative agents prime rate or the federal
funds effective rate, plus an applicable margin, (ii) adjusted LIBOR for
Eurodollar loans plus applicable margin, or (iii) Bankers' Acceptance plus
applicable margin for Canadian dollar loans. As a result, the Company's annual
interest cost in 2002 will fluctuate based on short-term interest rates.
Assuming no change in the amount outstanding during 2002, the impact on interest
expense
22
of a ten percent change in the average interest rate would be approximately $.5
million. As the interest rate is variable and is reflective of current market
conditions, the carrying value of the Global Credit Facility approximates the
fair value.
23
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Report of Independent Public Accountants.......................... 25
Consolidated Balance Sheets, December 31, 2001 and 2000........... 26
Consolidated Statements of Operations, Years ended December
31, 2001, 2000 and 1999....................................... 27
Consolidated Statements of Changes in Stockholders' Equity,
Years ended December 31, 2001, 2000 and 1999.................. 28
Consolidated Statements of Cash Flows, Years ended December
31, 2001, 2000 and 1999....................................... 29
Notes to Consolidated Financial Statements........................ 30
24
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders 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, 2001 and
2000,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, 2001. 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, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.
As explained in Notes 2 and 10 to the consolidated financial statements,
on January 1, 2001, the Company changed its method of accounting for derivative
instruments and hedging activities.
ARTHUR ANDERSEN LLP
Denver, Colorado
February 27, 2002
25
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
------------------------------
2001 2000
--------- ---------
(IN THOUSANDS)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ................................................ $ 15,196 $ 17,534
Accounts receivable ...................................................... 63,745 95,878
Inventories .............................................................. 1,689 521
Other .................................................................... 2,332 2,307
--------- ---------
Total current assets ............................................... 82,962 116,240
--------- ---------
PROPERTY AND EQUIPMENT, AT COST:
Gas and oil properties, successful efforts method of accounting .......... 849,628 575,991
Gas gathering and processing and other plant ............................. 89,343 81,873
Other .................................................................... 33,689 28,746
--------- ---------
Total property and equipment ....................................... 972,660 686,610
Less: Accumulated depreciation, depletion and amortization .............. 234,134 176,848
--------- ---------
Net property and equipment ......................................... 738,526 509,762
--------- ---------
OTHER ASSETS:
Goodwill, net ............................................................ 18,125 --
Other assets ............................................................. 5,362 3,533
--------- ---------
$ 844,975 $ 629,535
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable .......................................................... $ 59,172 $ 55,982
Accrued expenses .......................................................... 12,512 22,119
--------- ---------
Total current liabilities .......................................... 71,684 78,101
--------- ---------
BANK DEBT ................................................................... 120,570 54,000
DEFERRED INCOME TAXES ....................................................... 75,194 5,475
OTHER NON-CURRENT LIABILITIES ............................................... 2,299 3,066
COMMITMENTS AND CONTINGENCIES (Note 13)
STOCKHOLDERS' EQUITY:
Convertible preferred stock, $.10 par value
Authorized 2,500,000 shares; -- --
Common Stock, $.10 par value
Authorized 55,000,000 shares;
Outstanding 39,127,649 and 38,351,860 shares, respectively ............ 3,913 3,835
Additional paid-in capital ................................................ 534,790 516,911
Retained earnings (accumulated deficit) ................................... 37,855 (31,648)
Accumulated other comprehensive loss ...................................... (1,330) (205)
--------- ---------
Total stockholders' equity ......................................... 575,228 488,893
--------- ---------
$ 844,975 $ 629,535
========= =========
See accompanying notes to consolidated financial statements.
26
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31,
---------------------------------------------
2001 2000 1999
--------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
REVENUES:
Gas, oil and natural gas liquids sales .................................... $ 274,031 $ 216,968 $ 104,431
Gathering and processing .................................................. 23,245 18,283 11,968
Marketing and trading, net ................................................ 1,891 5,841 (786)
Drilling .................................................................. 14,828 11,472 5,645
Gain on sale of property .................................................. 10,078 -- 1,265
Change in derivative fair value ........................................... 897 -- --
Interest income and other ................................................. 1,354 1,346 888
--------- --------- ---------
Total revenues .................................................... 326,324 253,910 123,411
--------- --------- ---------
COSTS AND EXPENSES:
Gas and oil production .................................................... 32,060 25,488 18,446
Taxes on gas and oil production ........................................... 21,020 22,105 9,934
Gathering and processing costs ............................................ 10,855 7,212 5,853
Drilling operations ....................................................... 11,851 9,715 5,237
Exploration costs ......................................................... 34,195 11,001 10,013
Impairments of leasehold costs ............................................ 5,236 3,900 3,600
General and administrative ................................................ 22,742 11,614 9,203
Depreciation, depletion and amortization .................................. 74,371 50,417 44,215
Interest expense and other ................................................ 8,390 6,100 5,860
--------- --------- ---------
Total costs and expenses .......................................... 220,720 147,552 112,361
--------- --------- ---------
Income before income taxes and
cumulative effect of change in accounting principle ............ 105,604 106,358 11,050
Income tax provision
Current ................................................................... (1,200) (1,968) (903)
Deferred .................................................................. (36,927) (37,812) (3,390)
--------- --------- ---------
Net income before cumulative effect of change in accounting
principle ................................................................. 67,477 66,578 6,757
Cumulative effect of change in accounting principle .......................... 2,026 -- --
--------- --------- ---------
Net income ................................................................... 69,503 66,578 6,757
Preferred stock dividends .................................................... -- (875) (1,750)
--------- --------- ---------
Net income attributable to common stock ..................................... $ 69,503 $ 65,703 $ 5,007
========= ========= =========
Weighted average number of common shares outstanding:
Basic ..................................................................... 38,943 36,664 32,228
========= ========= =========
Diluted ................................................................... 40,227 37,897 32,466
========= ========= =========
Earnings per common share-Basic:
Income before cumulative effect of change in accounting
principle ............................................................... $ 1.73 $ 1.79 $ .16
Cumulative effect of change in accounting principle ....................... .05 -- --
--------- --------- ---------
Net income attributable to common stock ...................................... $ 1.78 $ 1.79 $ .16
========= ========= =========
Earnings per common share-Diluted:
Income before cumulative effect of change in accounting
principle ............................................................... $ 1.68 $ 1.76 $ .15
Cumulative effect of change in accounting principle ....................... .05 -- --
--------- --------- ---------
Net income attributable to common stock ...................................... $ 1.73 $ 1.76 $ .15
========= ========= =========
See accompanying notes to consolidated financial statements.
27
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
RETAINED ACCUMULATED
PREFERRED STOCK COMMON STOCK ADDITIONAL EARNINGS OTHER TOTAL
---------------- ---------------- PAID-IN (ACCUMULATED COMPREHENSIVE STOCKHOLDERS'
SHARES AMOUNT SHARES AMOUNT CAPITAL DEFICIT) INCOME (LOSS) EQUITY
------- ------ ------- ------ ---------- ----------- ------------- -------------
(IN THOUSANDS)
BALANCE AS OF DECEMBER 31,
1998......................... 1,000 $ 100 29,260 $ 2,926 $431,082 $ (102,358) $ -- $331,750
Stock options exercised......... -- -- 248 25 1,107 -- -- 1,132
Income tax benefit of
stock options exercised....... -- -- -- -- 600 -- -- 600
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 3,531 495,724 (97,351) 93 402,097
Stock options exercised......... -- -- 1,378 137 17,475 -- -- 17,612
Income tax benefit of
stock options exercised....... -- -- -- -- 3,779 -- -- 3,779
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 3,835 516,911 (31,648) (205) 488,893
Stock options exercised......... -- -- 776 78 11,085 -- -- 11,163
Income tax benefit of
stock options exercised...... -- -- -- -- 2,897 -- -- 2,897
Accelerated vesting of
options...................... -- -- -- -- 3,897 -- -- 3,897
Comprehensive income (loss):
Translation loss.............. -- -- -- -- -- -- (790) (790)
Cumulative effect of
change in accounting
principle (net of tax).... -- -- -- -- -- -- (4,449) (4,449)
Change in fair value of
derivative hedging
instruments............... -- -- -- -- -- -- 14,466 14,466
Hedge settlements reclassified
to income (net of tax).... -- -- -- -- -- -- (10,017) (10,017)
Unrealized loss on
marketable securities..... -- -- -- -- -- -- (335) (335)
Net income.................... -- -- -- -- -- 69,503 -- 69,503
---------- -------- --------
Total comprehensive income...... -- -- -- -- -- 69,503 (1,125) 68,378
------ ----- ------ ------- -------- ---------- -------- --------
BALANCE AS OF DECEMBER 31,
2001.......................... -- $ -- 39,128 $3,913 $534,790 $ 37,855 $ (1,330) $575,228
====== ===== ====== ====== ======== ========== ======== ========
See accompanying notes to consolidated financial statements.
28
TOM BROWN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31,
----------------------------------------
2001 2000 1999
--------- --------- --------
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ....................................................................... $ 69,503 $ 66,578 $ 6,757
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization ....................................... 74,371 50,417 44,215
Gain on sales of assets ........................................................ (10,078) -- (1,265)
Accelerated vesting of options ................................................. 3,897 -- --
Deferred tax provision ......................................................... 36,927 37,812 3,390
Dry hole costs ................................................................. 15,779 1,249 3,124
Impairments of leasehold costs ................................................. 5,236 3,900 3,600
Changes in operating assets and liabilities, net of
the effects from the purchase of Stellarton:
(Increase) decrease in accounts receivable ................................... 43,520 (42,232) (19,140)
(Increase) decrease in inventories ........................................... (109) 307 (296)
(Increase) decrease in other current assets .................................. 388 (1,541) (616)
Increase (decrease) in accounts payable and accrued
expenses ................................................................... (28,597) 15,549 22,644
(Increase) decrease in other assets, net ..................................... (2,937) 919 973
Advances from gas purchasers ................................................. -- -- (24,529)
--------- --------- --------
Net cash provided by operating activities .............................. 207,900 132,958 38,857
--------- --------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sales of assets .................................................. 52,366 9,681 2,573
Capital and exploration expenditures ........................................... (244,663) (140,719) (56,183)
Acquisition of Stellarton stock ................................................ (74,500) -- --
Direct costs on Stellarton acquisition ......................................... (3,107) -- --
Changes in accounts payable and accrued expenses for
capital expenditures ....................................................... (7,082) 13,300 (1,389)
--------- --------- --------
Net cash used in investing activities .................................. (276,986) (117,738) (54,999)
--------- --------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings of long-term bank debt .............................................. 109,812 20,000 26,000
Repayments of long-term bank debt .............................................. (54,000) (47,000) --
Preferred stock dividends ...................................................... -- (875) (1,750)
Proceeds from exercise of stock options ........................................ 11,163 17,679 1,732
--------- --------- --------
Net cash provided by (used in) financing
activities .......................................................... 66,975 (10,196) 25,982
--------- --------- --------
Effect of exchange rate changes on cash ............................................. (227) -- --
NET CHANGE IN CASH AND CASH EQUIVALENTS ............................................. (2,338) 5,024 9,840
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR ...................................... 17,534 12,510 2,670
--------- --------- --------
CASH AND CASH EQUIVALENTS AT END OF YEAR ............................................ $ 15,196 $ 17,534 $ 12,510
========= ========= ========
Supplemental disclosures of cash flow information: Cash paid during the year
for:
Interest ....................................................................... $ 7,219 $ 4,941 $ 4,051
Income taxes ................................................................... 7,421 840 --
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
Debt assumed in Stellarton Acquisition ......................................... 16,800 -- --
See accompanying notes to consolidated financial statements.
29
TOM BROWN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(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. The Company expanded its operations in Canada in
2001, establishing western Canada as a core area through the acquisition of
Stellarton Energy Corporation ("Stellarton"). This transaction was completed in
January 2001. The Canadian operations are focused in the Carrot Creek, Edson and
Davey Lake areas of the western sedimentary basin of Alberta.
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. In 2001, TBIFS
selectively sold many of the gathering and processing facilities received in the
Wildhorse asset distribution retaining only those gathering systems considered
integral to the Company's operations. The Wind River gathering system was the
main system retained.
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 (84 percent in 2001 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 were consolidated within the accompanying financial
statements for the periods prior to Wildhorse asset distribution. All
significant intercompany accounts and transactions have been eliminated. Certain
reclassifications have been made to amounts reported in previous years to
conform to the 2001 presentation.
Inventories
Inventories consist of pipe, other production equipment and natural
gas placed in storage. Inventories are stated at the lower of cost (principally
first-in, first-out) or estimated net realizable value.
30
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
costs, 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. The Company estimates the expected future cash flows of
its gas and oil properties and compares such future cash flows to the carrying
amount of the gas and oil properties to determine if the carrying amount is
recoverable. If the carrying amount exceeds the estimated undiscounted future
cash flows, the Company will adjust the carrying amount of the oil and gas
properties to fair value. The factors used to determine fair value include, but
are not limited to, estimates of proved reserves, future commodity pricing,
future production estimates, anticipated capital expenditures, and a discount
rate commensurate with the risk associated with realizing the expected cash
flows projected. There were no impairments of gas and oil properties in 2001,
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 or estimated fair
value upon acquisition and depreciated using the straight-line method based on
estimated useful lives.
Natural Gas Revenues
The Company utilizes the accrual method of accounting for natural
gas revenues whereby revenues are recognized as the Company's entitlement share
of gas is produced based on its working interests in the properties. The Company
records a receivable (payable) to the extent it receives less (more) than its
proportionate share of gas revenues. Using historical prices, the Company had
net gas balancing liabilities of approximately $1.2 million associated with
approximately .7 billion cubic feet ("Bcf") of gas at December 31, 2000. At
December 31, 2001, the imbalance position was not significant.
Foreign Currency Translation
The functional currency of the Company's Canadian subsidiary is the
Canadian dollar. For purposes of consolidation, substantially all assets and
liabilities of the Canadian operations are translated into U.S. dollars at
exchange rates in effect at the balance sheet dates. Unrealized currency
translation adjustments are accumulated as a separate component of accumulated
other comprehensive income within stockholders' equity. Income and expense items
are translated at average exchange rates during the year. As a result of the
change in the Canadian dollar relative to the U.S. dollar, the Company reported
a translation loss of $790,000 in 2001.
31
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.
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.
Recently Issued Accounting Standards
In June 2001, the Financial Accounting Standards Board ("FASB")
issued Statement of Financial Accounting Standards ("SFAS") No. 141, "Business
Combinations," which addresses financial accounting and reporting for business
combinations. SFAS No. 141 is effective for all business combinations initiated
after June 30, 2001 and for all business combinations accounted for under the
purchase method initiated before but completed after June 30, 2001. The adoption
of SFAS No. 141 is not expected to have a material impact on the Company's
financial position or results of operations.
In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other
Intangible Assets," which addresses, among other things, the financial
accounting and reporting for goodwill subsequent to an acquisition. The new
standard eliminates the requirement to amortize acquired goodwill; instead, such
goodwill shall be reviewed at least annually for impairment. SFAS No. 142 is
required to be adopted on January 1, 2002. The Company is analyzing the
provisions of SFAS No. 142, and expects that future annual amortization expense
will be reduced by approximately $.9 million, but has not yet determined whether
the other provisions of SFAS No. 142 will otherwise impact its financial
statements upon adoption.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations". SFAS No. 143 requires entities to record the fair value
of a liability for an asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity capitalizes a
cost by increasing the carrying amount of the related long-lived asset. Over
time, the liability is accreted to its present value each period, and the
capitalized cost is depreciated over the useful life of the related asset. Upon
settlement of the liability, an entity either settles the obligation for the
recorded amount or incurs a gain or loss upon settlement. SFAS No. 143 is
effective for fiscal years beginning after June 15, 2002. The Company will adopt
SFAS No. 143 on January 1, 2003, but has not yet quantified the effects of
adopting SFAS No. 143 on its financial position or results of operations.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets". SFAS No. 144 supersedes SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of". SFAS No. 121 did not address the accounting for a
segment of a business accounted for as a discontinued operation which resulted
in two accounting models for long-lived assets to be disposed of. SFAS No. 144
establishes a single accounting model for long-lived assets to be disposed of by
sale and requires that those long-lived assets be measured at the lower of
carrying amount or fair value less cost to sell, whether reported in continuing
operations or in discontinued operations. SFAS No. 144 is effective for fiscal
years beginning after December 15, 2001. The Company will adopt SFAS No. 144 on
January 1, 2002, and anticipates no impact on its financial position or results
of operations.
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 basis 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.
32
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 9, "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 2001, 2000 and 1999.
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, 2001, 2000 and 1999:
2001 2000 1999
------------------------------ ----------------------------- -------------------------------
PER PER PER
NET SHARE NET SHARE NET SHARE
INCOME SHARES AMOUNT INCOME SHARES AMOUNT INCOME SHARES AMOUNT
------- ------ ------ ------- ------ ------ ------- ------ -------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Basic EPS:
Net Income
Attributable to
Common Stock and
Share Amounts....... $69,503 38,943 $1.78 $65,703 36,664 $1.79 $5,007 32,228 $.16
Dilutive Securities:
Stock Options........ -- 1,284 -- -- 473 -- -- 238 --
Convertible
preferred stock......... -- -- -- 875 760 -- -- -- --
------- ------ ----- ------- ------ ----- ------ ------ ----
Diluted EPS:
Net Income
Attributable to
Common Stock and
Assumed Share
Amounts............. $69,503 40,227 $1.73 $66,578 37,897 $1.76 $5,007 32,466 $.15
======= ====== ===== ======= ====== ===== ====== ====== ====
Options to purchase 1,180,000 and 1,447,000 shares of common stock
in 2001 and 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 because their assumed
conversion would be antidilutive.
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). The Company received shares of stock valued at approximately
$700,000 in June 1999 in settlement of an outstanding receivable from a working
interest owner. In conjunction with the Stellarton acquisition in January 2001,
the Company assumed long-term debt of $16.8 million (see Note 3).
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 items between net income as reflected in the statement of operations
and comprehensive income for the years ended December 31, 2001, 2000 and 1999
were an unrealized (loss)/gain on marketable securities and a translation loss
in 2001.
33
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 Stellarton
On January 12, 2001, the Company completed an acquisition of 97.2%
of the outstanding common shares of Stellarton. The remaining shares of
Stellarton were then subsequently acquired pursuant to the compulsory
acquisition provisions of the Business Corporation Act (Alberta). Including
assumed debt of approximately $16.8 million, this business combination had a
cash value of approximately $95 million and was accounted for as a purchase. The
purchase price exceeded the fair value of the net assets of Stellarton by $20
million which was recorded as goodwill, and a portion of which was amortized in
2001 on a straight-line basis utilizing a twenty year life. Effective January 1,
2002 the Company adopted SFAS No. 142, "Goodwill and Other Intangible Assets"
which eliminates the amortization of this goodwill in future periods. The net
proved reserves associated with the Stellarton properties were estimated to be
75.8 billion cubic feet equivalent of gas (Bcfe) (unaudited) as of the closing
date. The results of operations of Stellarton are included with the results of
the Company from January 12, 2001 (closing date) forward.
The purchase price was allocated as follows (in thousands):
Cash paid for acquisition:
Long-term debt incurred $ 74,500
Long-term debt assumed 16,800
Direct acquisition costs 3,107
--------
Total cash consideration 94,407
Allocation of acquisition costs:
Oil and gas properties - proved (117,000)
Unproved properties (9,975)
Deferred income taxes 36,375
Gas sales contracts assumed 10,825
Net working capital deficit assumed 5,368
--------
Goodwill $ 20,000
========
In the acquisition costs identified above, the Company recorded a
deferred income tax liability of $36.4 million to recognize the difference
between the historical tax basis of the Stellarton assets and the acquisition
costs recorded for book purposes. The recorded book value of the proved oil and
gas properties and goodwill was increased to recognize this tax basis
differential.
The gas sales contracts assumed in conjunction with the acquisition
represented contractual obligations associated with the sale of natural gas at
fixed prices below market conditions. These contracts were subsequently
purchased (for an amount approximately equal to the original liability recorded)
and cancelled in the quarter ended June 30, 2001.
Pro Forma Results of Operations (Unaudited)
The following table reflects the unaudited pro forma results of
operations for the twelve months ended December 31, 2001 and 2000 as though the
Stellarton Acquisition had occurred on January 1 of each period presented. The
pro forma amounts are not necessarily representative of the results that may be
reported in the future.
Years Ended
December 31,
---------------------------
2001 2000
-------- --------
(In thousands, except
per share data
Revenues..................................................... $328,267 $278,794
Net Income................................................... 69,503 64,008
Basic net income per share................................... 1.78 1.75
Diluted net income per share................................. 1.73 1.71
34
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
Bcfe of gas as of the closing date of July 1, 1999. Approximately 65,000 net
undeveloped acres were also acquired.
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 year ended December 31,
1999 assuming that the Unocal Acquisition occurred on January 1, 1999.
Years ended
December 31,
--------------------------
1999
--------------------------
(In thousands, except for
per share amounts)
Revenues $226,141
========
Net income (loss) $ 9,341
========
Net income (loss) attributable to common stock $ 7,591
========
Net income (loss) per common share
Basic $ .22
========
Diluted $ .21
========
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.
Property Sales
During May 2001, the Company sold its interest in oil and gas
properties primarily located in Oklahoma, with a net book value of $14.4
million, for net cash proceeds of $24.5 million. The resulting gain of $10.1
million is reflected in the Consolidated Statement of Operations.
In June and October 2001, the Company sold certain of the gathering
and processing assets originally received in the Wildhorse distribution
completed in 2000. The systems sold were considered non-strategic to the
Company's operations and as these divestitures were part of the Wildhorse
integration process, the net cash proceeds of $24.0 million were recorded as a
reduction to the investment in gathering assets.
35
Proceeds derived from the 2001 property sales were utilized to repay
bank indebtedness.
Sale of DJ Basin Properties
In June and October 1999, the Company sold its interest in the DJ
Basin of Colorado for $2.3 million. The properties had a net book value of $1.1
million and, accordingly, a gain of $1.2 million was recorded on the sale.
Proceeds from the sale of these properties 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 an original 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%.
On June 30, 2000, the Company entered into a new $125 million credit
facility (the "New Credit Facility") that was to mature in June 2003. Under the
terms of the New Credit Facility, the borrowing base was established at $225
million. At December 31, 2000, the outstanding balance on the New Credit
Facility was $54 million at an average interest rate of 7.9%.
On March 20, 2001, as part of the final financing of the Stellarton
acquisition, the Company repaid and cancelled its previous $125 million
revolving credit facility and entered into a new $225 million credit facility
(the "Global Credit Facility"). The Global Credit Facility is comprised of: a
$75 million line of credit in the U.S. and a $55 million line of credit in
Canada which both mature in March 2004, and a $95 million five-year term loan in
Canada. The borrowing base under the Global Credit Facility was set at $300
million. The Global Credit Facility allows the lenders one scheduled
redetermination of the borrowing base each December. In addition, the lenders
may elect to require one unscheduled redetermination in the event the borrowing
base utilization exceeds 50% of the borrowing base at any time for a period of
15 consecutive business days. At December 31, 2001, the Company had borrowings
outstanding under the Global Credit Facility totaling $120.6 million or 40% of
the borrowing base at an average interest rate of 4. 1%. The amount available
for borrowing under the Global Credit Facility at December 31, 2001 was $104.4
million.
Borrowings under the Global Credit Facility are unsecured and bear
interest, at the election of the Company, at a rate equal to (i) the greater of
the global administrative agents prime rate or the federal funds effective rate
plus an applicable margin, (ii) adjusted LIBOR for Eurodollar loans plus
applicable margin, or (iii) Bankers' Acceptances plus applicable margin for
Canadian dollar loans. Interest on amounts outstanding under the Global Credit
Facility is due on the last day of each quarter for prime based loans, and in
the case of Eurodollar loans with an interest period of more than three months,
interest is due at the end of each three month interval.
The Global Credit Facility contains certain financial covenants and
other restrictions similar to the limitations associated with the cancelled
credit facility. The financial covenants of the Global Credit Facility require
the Company to maintain a minimum consolidated tangible net worth of not less
than $350 million (adjusted upward by 50% of quarterly net income and 50% of the
net cash proceeds of any stock offering) and the Company will not permit its
ratio of (i) indebtedness to (ii) earnings before interest expense, state and
federal taxes and depreciation, depletion and amortization expense and
exploration expense to be more than 3.0 to 1.0 as calculated at the end of each
fiscal quarter.
36
(5) TAXES
The income tax (expense) benefit was different from amounts computed
by applying the statutory federal and state income tax rates for the following
reasons:
2001 2000 1999
-------- -------- --------
(IN THOUSANDS)
Tax expense at 35% of income
before income taxes and change in
accounting principle ............................................. $(36,961) $(37,225) $ (3,868)
State tax expense net of federal benefit ............................. (2,112) (2,127) (221)
Canadian Crown payments (net of Alberta Royalty
Tax Credit) not deductible for tax purposes ...................... (4,136) -- --
Canadian resource allowance .......................................... 3,556 -- --
Canadian expenses deductible in the United States .................... 1,845 -- --
Canadian Large Corporation Tax ....................................... (335) -- --
Franchise and other taxes - United States ............................ (486) (1,614) (682)
Adjustments to prior periods due to filed returns .................... 502 -- --
Valuation allowance adjustment ....................................... -- 1,953 622
Other ................................................................ -- (767) (144)
-------- -------- --------
Total income tax expense ............................................... $(38,127) $(39,780) $ (4,293)
======== ======== ========
Deferred income taxes result from recognizing income and expenses at
different times for financial and tax reporting. In the United States, the
largest differences are the tax effect of the capitalization of certain
development, exploration and other costs under the successful efforts method of
accounting. In Canada, differences result in part from accelerated cost recovery
of oil and gas capital expenditures for tax purposes.
37
The components of the net deferred tax liability by geographical
segment at December 31, 2001 and 2000 were as follows (all items were located
within the United States as of December 31, 2000):
DECEMBER 31, 2001
UNITED STATES CANADA TOTAL
------------- ------ -----
Deferred tax assets: (IN THOUSANDS)
Net operating loss carryforward ................................... $ 6,918 $ 302 $ 7,220
Percentage depletion carryforward ................................. 2,178 -- 2,178
Alternative minimum tax credit carryforward ....................... 5,190 -- 5,190
Other ............................................................. 300 -- 300
-------- -------- --------
Total gross deferred tax assets ............................... 14,586 302 14,888
Deferred tax liabilities:
Property and equipment ............................................ (55,119) (34,558) (89,677)
Other ............................................................. (405) -- (405)
-------- -------- --------
Total gross deferred tax liabilities .......................... (55,524) (34,558) (90,082)
-------- -------- --------
Net deferred tax liabilities .................................. $(40,938) $(34,256) $(75,194)
======== ======== ========
DECEMBER 31, 2000
UNITED STATES
-----------------
(IN THOUSANDS)
Deferred tax assets:
Net operating loss carryforward.............................. $ 4,845
Percentage depletion carryforward............................ 2,178
Alternative minimum tax credit carryforward.................. 5,343
Other........................................................ 36
---------
Total gross deferred tax assets.......................... 12,402
Deferred tax liabilities:
Property and equipment....................................... (17,877)
---------
Total gross deferred tax liabilities..................... (17,877)
---------
Net deferred tax liabilities............................. $ (5,475)
=========
The Alternative Minimum Tax (AMT) credit carryforward available to
reduce future U.S. Federal regular taxes aggregated $5,190,000 at December 31,
2001. This amount may be carried forward indefinitely. U.S. Federal regular and
AMT net operating loss carryforwards at December 31, 2001 were approximately
$18,700,000 and $15,700,000, respectively, and will expire in 2019. AMT net
operating loss carryforwards can be used to offset 90% of AMT income in future
years. Realization of the benefit of these carryforwards is dependent upon the
Company's ability to generate taxable earnings in future periods.
Percentage depletion carryforwards available to reduce future U.S.
Federal taxable income aggregated $6,224,000 at December 31, 2001. This amount
may be carried forward indefinitely.
Canadian net operating losses available to reduce future Canadian
Federal income taxes were $700,000 ($1,084,000 CDN) at December 31, 2001 and
will expire in 2006.
Canadian tax pools relating to the exploration, development and
production of oil and natural gas which are available to reduce future Canadian
Federal income taxes aggregated approximately $55,218,000 ($85,474,000 CDN) at
December 31, 2001. These pool balances are deductible on a declining balance
basis ranging from 10% to 100% of the balance annually. The amounts may be
carried forward indefinitely.
38
In conjunction with the acquisition of Stellarton in January 2001,
the purchase price allocation resulted in a difference between the book and tax
basis of approximately U.S. $63 million. Based upon Stellarton's historical tax
rate of 43%, a deferred tax liability of approximately $36.4 million was
recognized.
(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 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,
----------------------------------------
2001 2000 1999
-------- -------- --------
(IN THOUSANDS)
Revenues ...................... $123,767 $111,756 $ 68,013
Operating expenses ............ 122,776 108,370 68,524
-------- -------- --------
Net trading margin ............ $ 991 $ 3,386 $ (511)
======== ======== ========
(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, 2001, of which
39,127,649 shares and 38,351,860 shares were outstanding at December 31, 2001
and 2000, 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 stockholders
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
39
redemption of the Rights. Until the Distribution Date occurs, the certificates
representing shares of the Company's Common Stock also evidence the Rights.
Following the Distribution Date, the Rights will be evidenced by separate
certificates.
The provisions described above may tend to deter any potential
unsolicited tender offers or other efforts to obtain control of the Company that
are not approved by the Board of Directors and thereby deprive the stockholders
of opportunities to sell shares of the Company's Common Stock at prices higher
than the prevailing market price. On the other hand, these provisions will tend
to assure continuity of management and corporate policies and to induce any
person seeking control of the Company or a business combination with the Company
to negotiate on terms acceptable to the then elected Board of Directors.
Preferred Stock
In January 1996, in connection with the KNPC Acquisition the Company
issued 1,000,000 shares of its $1.75 Convertible Preferred Stock, Series A (the
"Preferred Stock") to the seller. There are 2,500,000 shares of Preferred Stock
authorized. The holder of the Preferred Stock 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 did not 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, 2001, options to purchase 390,700 shares of the
Company's common stock were outstanding under the 1989 Plan. These options will
expire between 2003 and 2009 if not previously exercised.
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 aggregate number of shares was subsequently increased to 4,100,000
in January 2001. The exercise price, vesting and duration of the options may
vary and will be determined at the time of issuance. Options to purchase
2,767,700 shares of the Company's Common Stock were outstanding under this plan
as of December 31, 2001.
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 stockholders 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 378,700 and 490,000 shares
of the Company's Common Stock were granted in 2001 and 2000, respectively. 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. Options to purchase 760,600 shares
of the Company's Common Stock were outstanding under this plan as of December
31, 2001.
40
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:
YEARS ENDED DECEMBER 31,
----------------------------------------------------------------------
2001 2000 1999
--------------------- ---------------------- --------------------
WEIGHTED WEIGHTED WEIGHTED
SHARES AVERAGE SHARES AVERAGE SHARES AVERAGE
UNDER EXERCISE UNDER EXERCISE UNDER EXERCISE
OPTION PRICE OPTION PRICE OPTION PRICE
--------- --------- ---------- --------- -------- -------
(SHARES IN THOUSANDS)
Outstanding, beginning of year..... 3,412 $ 14.52 4,139 $ 13.77 3,402 $13.22
Granted............................. 1,531 29.56 852 15.14 1,178 13.91
Exercised........................... (778) 14.50 (1,378) 12.67 (248) 6.98
Cancellations....................... (246) 26.45 (201) 14.77 (193) 13.56
----- ------ -----
Outstanding, end of year............ 3,919 19.60 3,412 14.52 4,139 13.77
===== ====== =====
Exercisable, end of year............ 1,331 14.24 1,659 14.22 2,226 13.10
===== ====== =====
Available for grant, end of year.... 1,305 1,722 2,392
===== ===== =====
The weighted average fair value of options granted during the years
ended December 31, 2001, 2000, and 1999 was $18.12, $9.78, and $9.72,
respectively.
The following table summarizes information about stock options
outstanding at December 31, 2001:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------------------ ---------------------------------------
NUMBER OF
NUMBER OF SHARES WEIGHTED SHARES
UNDER AVERAGE WEIGHTED AVERAGE UNDER WEIGHTED AVERAGE
RANGE OF OUTSTANDING LIFE EXERCISE EXERCISABLE EXERCISE
EXERCISE PRICES OPTIONS (YEARS) PRICE OPTIONS PRICE
--------------- ---------------- -------- ---------------- -------------- ----------------
(SHARES IN THOUSANDS)
$3.81 to 11.88............ 140 2.50 $ 7.89 135 $ 7.85
$11.94 to 13.50........... 1,000 6.31 12.92 322 12.84
$13.63 to 15.69........... 1,112 5.98 15.14 787 15.25
$16.06 to 23.75........... 469 8.77 20.91 82 19.70
$23.89 to 30.13........... 321 9.32 27.47 5 26.46
$31.00 to 34.19........... 877 9.13 31.15 -- 34.00
----- -----
3,919 7.25 19.60 1,331 14.24
===== =====
In January 2001 the Company's Chairman and Chief Executive Officer
resigned to become the United States Secretary of Commerce. The Company
accelerated the vesting of 228,300 of his outstanding stock options upon his
resignation and as a result of this modification to the initial terms of these
stock options, a new measurement date was established. Based upon the difference
between the market price of the Company's stock on the date the stock options
were amended and the exercise price of the stock options, a non-cash pre-tax
charge to earnings of $3.8 million was recognized.
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 grants
of options under the stock option plans. Alternatively, if compensation costs
for these plans had been determined in accordance with SFAS No. 123, the
Company's net income and net income per common share would approximate the
following pro forma amounts:
YEARS ENDED DECEMBER 31,
-------------------------------------
2001 2000 1999
-------- -------- --------
(IN THOUSANDS,
EXCEPT PER SHARE AMOUNTS)
Net Income
As Reported.................................................. $69,503 $65,703 $5,007
Pro Forma.................................................... $66,570 $63,693 $ 451
Basic Net Income per Common Share:
As Reported.................................................. $ 1.78 $ 1.79 $ .16
Pro Forma.................................................... $ 1.71 $ 1.74 $ .01
Diluted Net Income per Common Share:
As Reported.................................................. $ 1.73 $ 1.76 $ .15
Pro Forma.................................................... $ 1.65 $ 1.70 $ .01
41
The fair value of each option is estimated as of the date of grant
using the Black-Scholes option-pricing model with the following weighted-average
assumptions used for grants in 2001, 2000, and 1999, respectively: (i) risk-free
interest rates of 4.46, 6.25, and 6.20 percent; (ii) expected lives of 7.0, 7.0
and 7.0 years, (iii) expected volatility of 56.0, 53.7, and 47.6 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. On
December 1, 2001, the Company amended and restated its 401(k) retirement plan.
The Company has, at its discretion, a policy to match employee contributions to
the plan. As of December 31, 2001, the Company's policy was to match 100% of
the employee contribution up to a total match of seven percent of the employee's
salary. The match for the years ended December 31, 2001, 2000 and 1999, was
approximately $864,000, $492,000 and $422,000, 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.
Derivative Instruments and Hedging Activities
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 collar
arrangements (put and call options) to hedge approximately 40% of the Company's
expected 2001 U.S. gas production. These positions were open as of January 1,
2001 when the Company adopted SFAS 133 and SFAS 138. 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 Loss 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. As of December 31, 2001, the Company had
no outstanding cash flow hedges. The Company received cash settlements of $15.4
million in 2001, which were recognized as increases in gas and oil sales.
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 did not qualify for hedge accounting.
Accordingly, upon adoption of SFAS 133, these basis swaps resulted 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 asset of $3.2 million. A $.9 million gain was
recognized in conjunction with the change in the value of these contracts in the
year ended December 31, 2001. Cash receipts of $4.1 million were received during
this period. No basis swaps were outstanding at December 31, 2001.
42
In August 2001, the Company entered into NYMEX based swaps for the
September and October 2001 contract periods. Basis swaps were purchased on these
quantities to correlate the volumes back to markets where the Company actually
delivers gas. Cash settlements of $2.0 million were received on these contracts
which increased gas and oil sales.
In October 2001, the Company entered into NYMEX based swaps for the
November 2001 contract period. Basis swaps were purchased on these quantities to
correlate the volumes back to markets where the Company actually delivers gas. A
cash settlement of $1.5 million was paid on the contracts which decreased gas
and oil sales.
As of December 31, 2001, the Company had no open derivative
contracts.
(11) RELATED PARTIES AND SIGNIFICANT CUSTOMERS
Related Parties
Certain of the Company's 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, 2001, 2000 and 1999, were approximately $173,000,
$162,000 and $97,000, respectively. The Company also paid approximately $41,000,
$44,000 and $38,000 during the years ended December 31, 2001, 2000 and 1999,
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, 2001, 2000, and 1999, the Company billed $621,000, $612,000 and
$579,000, respectively, to such partnership for their share of certain leasehold
and drilling costs.
In addition, a director of the Company is also a director of a
drilling contractor that has performed drilling services on wells operated by
the Company. The fees charged for these services were $787,000 and $1,860,000
for the years ended December 31, 2000 and 1999, respectively. No fees were paid
in 2001.
In management's opinion, the above described transactions and
services were provided on the same terms as could be obtained from non-related
sources.
Significant Customers
Gas and oil sales to Conoco, Inc. accounted for 11%, 11% and 12% of
gas and oil sales for the years ended December 31, 2001, 2000 and 1999,
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.
43
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 four reportable segments: (i) gas and oil
exploration and development for the United States and Canada, (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, east Texas and the western sedimentary basin of Canada. 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 (in thousands):
AS OF OR YEAR ENDED DECEMBER 31, 2001
-----------------------------------------------------------------------------
GAS & OIL GAS & OIL
EXPLORATION EXPLORATION MARKETING,
& & GATHERING
DEVELOPMENT DEVELOPMENT & TOTAL
(UNITED STATES) (CANADA) PROCESSING DRILLING SEGMENTS
---------------- ----------- ----------- -------- --------
Revenues from external purchasers ......... $162,158 $ 30,133 $266,386 $14,828 $473,505
Intersegment revenues ..................... 83,991 -- 6,556 12,777 103,324
Depreciation, depletion and amortization .. 55,692 14,079 2,951 1,649 74,371
Segment profit ............................ 85,932 5,593 9,671 5,141 106,337
Assets .................................... 644,483 165,399 59,333 19,606 888,821
Capital and exploration expenditures ...... 316,934 31,280 9,300 5,237 362,751
AS OF OR YEAR ENDED DECEMBER 31, 2000
------------------------------------------------------------
GAS & OIL
EXPLORATION MARKETING
& GATHERING
DEVELOPMENT & TOTAL
(UNITED STATES) 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
AS OF OR YEAR ENDED DECEMBER 31, 1999
----------------------------------------------------------
GAS & OIL
EXPLORATION MARKETING,
& GATHERING
DEVELOPMENT & TOTAL
(UNITED STATES) 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
44
The following tables reconcile segment information to consolidated
totals:
AS OF OR YEARS ENDED DECEMBER 31,
------------------------------------------
2001 2000 1999
---------- ---------- ----------
(IN THOUSANDS)
Revenues
Revenue from external purchasers................................... $473,505 $393,598 $207,468
Marketing and trading expenses offset against
related revenues for net presentation.......................... (170,774) (148,480) (91,439)
Gain on sale of property........................................... 10,078 -- 1,265
Intersegment revenues.............................................. 103,324 61,459 25,713
Intercompany eliminations.......................................... (89,809) (52,667) (19,596)
-------- -------- --------
Total consolidated revenues............................... $326,324 $253,910 $123,411
======== ======== ========
Profit
Total reportable segment profit/loss............................... $106,337 $113,043 $ 17,151
Interest and other................................................. (6,139) (5,967) (6,825)
Gain on sale of property........................................... 10,078 -- 1,265
Eliminations and other............................................. (4,672) (718) (541)
-------- -------- --------
Income before income taxes......................................... $105,604 $106,358 $ 11,050
======== ======== ========
Depreciation, depletion and amortization
Total reportable segment depreciation, depletion and
amortization.................................................... $ 74,371 $ 51,519 $ 44,963
Elimination and other.............................................. -- (1,102) (748)
-------- -------- --------
$ 74,371 $ 50,417 $ 44,215
======== ======== ========
Assets
Total reportable segment assets.................................... $888,821 $669,689 $567,156
Elimination and other.............................................. (43,846) (40,154) (30,857)
-------- -------- --------
$844,975 $629,535 $536,299
======== ======== ========
(13) COMMITMENTS AND CONTINGENCIES
The Company's operations are subject to numerous governmental
regulations that may give rise to claims against the Company. In addition, the
Company is a defendant in various lawsuits generally incidental to its business.
The Company does not believe that the ultimate resolution of such litigation
will have a material adverse effect on the Company's financial position, results
of operations or cash flows.
Lease Commitments
At December 31, 2001, the Company had long-term leases through 2004
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)
2002...................................................... $1,502
2003...................................................... 1,353
2004...................................................... 191
------
$3,046
======
Total rental expense incurred for the years ended December 31, 2001,
2000 and 1999, was approximately $1,558,000, $1,447,000, and $1,139,000,
respectively, all of which represented minimum rentals under non-cancelable
operating leases.
45
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)
2002 $ 5,176
2003 4,088
2004 2,618
2005 1,852
2006 573
Thereafter 596
------
$14,903
=======
Processing Commitment
In March 2001, the Company entered into a new gas processing
agreement with a third party to expand available capacity for its gas production
from the White River Dome coal bed methane project in the Piceance Basin. The
plant commenced operations in October 2001. As processing fees, the Company is
obligated to reimburse the third party for certain variable expenses of the
plant associated with the processed volumes and compression made available
during the ten-year term of this agreement. Additionally, the Company pays the
third party $189,000/month to cover the plants fixed operating costs and capital
recovery over the term of this agreement.
Drilling Obligation
To assure the availability of a drilling rig in conjunction with the
continuing exploration program at the Deep Valley prospect in West Texas, the
Company entered into a two-year commitment with a drilling contractor in 2001.
The rig became available on March 1, 2002 after which a 90-day period is allowed
under the terms of the agreement to mobilize the rig and commence the two-year
drilling obligation. Under the terms of this arrangement, the Company is
required to pay a daywork rate of $20,100/day during drilling operations,
$16,700/day for rig moves and a special standby fee of $6,000/day during the
initial 90-day commencement period.
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, 2001. 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.
46
(14) QUARTERLY FINANCIAL DATA (UNAUDITED)
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER TOTAL
-------- ------- ------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Year ended December 31, 2001
Revenues....................................... $118,684 $ 95,386 $ 59,252 $ 53,002 $326,324
Gross profit (1)............................... 90,609 62,460 45,155 37,008 235,232
Net income attributable to common
stock...................................... 37,466 26,234 5,770 33 69,503
Net income per common share (2)
Basic...................................... .97 .67 .15 -- 1.78
Diluted.................................... .93 .65 .14 -- 1.73
Year ended December 31, 2000
Revenues....................................... $ 45,681 $ 53,388 $ 65,400 $ 89,441 $253,910
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
- ---------------
(1) Gross Profit is computed as the excess of gas and oil sales and
marketing, trading gathering and processing revenues over operating
expenses. Operating expenses are those associated directly with gas
and oil sales 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 per share does not
agree with year-to-date net income per share as each period's
computation is based on the weighted average number of common shares
outstanding during that period.
(15) SUPPLEMENTAL INFORMATION RELATED TO GAS AND OIL ACTIVITIES
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,
--------------------------------------------
2001 2000 1999
---------- --------- ----------
(IN THOUSANDS)
Capitalized costs
Proved gas and oil properties............................... $780,300 $ 526,269 $ 427,676
Unproved gas and oil properties............................ 69,328 49,722 42,785
--------- --------- ---------
Total gas and oil properties............................... 849,628 575,991 470,461
Less: Accumulated depreciation, depletion and
amortization........................................ (213,297) (160,738) (116,403)
--------- --------- ---------
Net capitalized costs...................................... $636,331 $ 415,253 $ 354,058
========= ========= =========
47
UNITED
STATES CANADA TOTAL
-------- ------- -------
(IN THOUSANDS)
2001
Costs incurred
Proved property acquisition costs ...................... $ 3,649 $ 85,025 $ 88,674
Unproved property acquisition costs .................... 16,496 14,132 30,628
Exploration costs ...................................... 55,357 2,585 57,942
Development costs ...................................... 138,815 24,395 163,210
-------- -------- --------
Total ............................................... $214,317 $126,137 $340,454
======== ======== ========
2000
Costs incurred
Proved property acquisition costs ...................... $ 17,111 $ -- $ 17,111
Unproved property acquisition costs .................... 16,831 -- 16,831
Exploration costs ...................................... 18,362 -- 18,362
Development costs ...................................... 74,406 -- 74,406
-------- -------- --------
Total ............................................... $126,710 $ -- $126,710
======== ======== ========
1999
Costs incurred
Proved property acquisition costs (1) .................. $ 65,753 -- $ 65,753
Unproved property acquisition costs .................... 6,945 -- 6,945
Exploration costs ...................................... 12,016 -- 12,016
Development costs ...................................... 33,232 -- 33,232
-------- -------- --------
Total ............................................... $117,946 $ -- $117,946
======== ======== ========
- ---------------
(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, were principally prepared by independent petroleum consultants. The
reserve estimates for the years ended December 31, 2001 and 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. The Company's gas and oil reserves are located in the United
States and Canada.
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.
48
The standardized measure of discounted future net cash flows does
not purport to present, nor should it be interpreted to present, the fair value
of the Company's gas and oil reserves. An estimate of fair value would also take
into account, among other things, the recovery of reserves not presently
classified as proved, anticipated future changes in prices and costs and a
discount factor more representative of the time value of money and the risks
inherent in reserve estimates.
Quantities of Gas and Oil Reserves (Unaudited)
The following table presents estimates of the Company's net proved
and proved developed natural gas and oil reserves (including natural gas
liquids).
RESERVE QUANTITIES
-------------------------------------------------------------------------------
GAS OIL(1)
(MMCF) (MBLS)
--------------------------------------- ---------------------------------
UNITED UNITED
STATES CANADA TOTAL STATES CANADA TOTAL
-------- ------- ------- -------- ------ ------
Proved reserves:
Estimated reserves at
December 31, 1998 .................... 372,022 -- 372,022 5,682 -- 5,682
Revisions of previous estimates ... (8,571) -- (8,571) 1,505 -- 1,505
Purchases of minerals in place .... 65,982 -- 65,982 6,989 -- 6,989
Extensions and discoveries ........ 58,032 -- 58,032 292 -- 292
Sales of minerals in place ........ (1,018) -- (1,018) (22) -- (22)
Production ........................ (40,514) -- (40,514) (1,445) -- (1,445)
------- ------- ------- ------- ------ -------
Estimated reserves at
December 31, 1999 .................... 445,933 -- 445,933 13,001 -- 13,001
Revisions of previous estimates ... 50,852 -- 50,852 (311) -- (311)
Purchases of minerals in place .... 28,960 -- 28,960 17 -- 17
Extensions and discoveries ........ 60,827 -- 60,827 470 -- 470
Sales of minerals in place ........ -- -- -- (137) -- (137)
Production ........................ (51,199) -- (51,199) (1,847) -- (1,847)
------- ------- ------- ------- ------ -------
Estimated reserves at
December 31, 2000 .................... 535,373 -- 535,373 11,193 -- 11,193
Revisions of previous estimates ... (47,647) (7,058) (54,705) (49) (112) (161)
Purchases of minerals in place .... 3,000 58,809 61,809 -- 2,838 2,838
Extensions and discoveries ........ 164,561 14,920 179,481 2,937 648 3,585
Sales of minerals in place ........ (16,072) (483) (16,555) (181) (169) (350)
Production ........................ (57,163) (6,661) (63,824) (1,797) (301) (2,098)
------- ------- -------- ------- ------ -------
Estimated reserves at
December 31, 2001 .................... 582,052 59,527 641,579 12,103 2,904 15,007
======= ======= ======== ======= ===== ========
Proved developed reserves:
December 31, 1998 .................... 263,747 -- 263,747 4,029 -- 4,029
December 31, 1999 .................... 333,858 -- 337,858 11,398 -- 11,398
December 31, 2000 .................... 431,824 -- 431,824 10,089 -- 10,089
December 31, 2001 .................... 428,719 51,392 480,111 9,628 2,339 11,967
- ---------------
(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 with 5.1 million barrels of
proved developed reserves of natural gas liquids remaining at December 31,
2000. For 2001, liquids production was 1.1 million barrels in the United
States and .1 million barrels in Canada. At December 31, 2001 proved
developed reserves included 7.0 million barrels of natural gas liquids of
which 1.4 million barrels were associated with the Canadian properties.
49
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Gas
and Oil Reserves (Unaudited)
DECEMBER 31, 2001
---------------------------------------------
UNITED
STATES CANADA TOTAL
----------- ---------- -----------
(IN THOUSANDS)
Future cash flows........................................... $1,448,747 $188,317 $1,637,064
Future production costs..................................... (530,791) (57,248) (588,039)
Future development costs.................................... (164,226) (5,525) (169,751)
---------- -------- ----------
Future net cash flows before tax............................ 753,730 125,544 879,274
Future income taxes......................................... (89,389) (30,538) (119,927)
---------- -------- ----------
Future net cash flows after tax............................. 664,341 95,006 759,347
Annual discount at 10%...................................... (275,838) (30,813) (306,651)
---------- -------- ----------
Standardized measure of discounted future net cash
flows................................................... $ 388,503 $ 64,193 $ 452,696
========== ======== ==========
Discounted future net cash flows before income taxes........ $ 429,906 $ 71,382 $ 501,288
========== ======== ==========
DECEMBER 31, 2000
---------------------------------------------
UNITED
STATES CANADA TOTAL
------------ ---------- ----------
(IN THOUSANDS)
Future cash flows........................................... $5,028,357 $ -- $5,028,357
Future production costs..................................... (857,767) -- (857,767)
Future development costs.................................... (89,216) -- (89,216)
---------- ------- ----------
Future net cash flows before tax............................ 4,081,374 -- 4,081,374
Future income taxes......................................... (1,409,295) -- (1,409,295)
---------- ------- ----------
Future net cash flows after tax............................. 2,672,079 -- 2,672,079
Annual discount at 10%...................................... (1,196,324) (1,196,324)
---------- ------- ----------
Standardized measure of discounted future net cash
flows................................................... $1,475,755 $ -- $1,475,755
========== ======= ==========
Discounted future net cash flows before income taxes........ $2,187,925 $ -- $2,187,925
========== ======= ==========
DECEMBER 31, 1999
---------------------------------------------
UNITED
STATES CANADA TOTAL
------------ ---------- ----------
(IN THOUSANDS)
Future cash flows........................................... $1,107,515 $ -- $1,107,515
Future production costs..................................... (320,397) -- (320,397)
Future development costs.................................... (85,712) -- (85,712)
---------- ------- ----------
Future net cash flows before tax............................ 701,406 -- 701,406
Future income taxes......................................... (119,950) -- (119,950)
---------- ------- ----------
Future net cash flows after tax............................. 581,456 -- 581,456
Annual discount at 10%...................................... (247,897) -- (247,897)
Standardized measure of discounted future net cash
flows................................................... $ 333,559 $ -- $ 333,559
========== ======== ==========
Discounted future net cash flows before income taxes........ $ 393,423 $ -- $ 393,423
========== ======== ==========
50
Changes in Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
YEAR ENDED DECEMBER 31, 2001
---------------------------------------------
UNITED
STATES CANADA TOTAL
------------ ---------- ----------
(IN THOUSANDS)
Gas and oil sales, net of production costs(1) ................ $ (180,218) $ (24,926) $ (205,144)
Net changes in anticipated prices and production cost ........ (1,821,163) (66,916) (1,888,079)
Extensions and discoveries, less related costs ............... 92,376 20,262 112,638
Changes in estimated future development costs ................ (868) -- (868)
Previously estimated development costs incurred .............. 36,691 7,693 44,384
Net change in income taxes ................................... 670,767 (7,188) 663,579
Purchase of minerals in place ................................ 3,500 153,017 156,517
Sales of minerals in place ................................... (61,623) (1,155) (62,778)
Accretion of discount ........................................ 218,793 -- 218,793
Revision of quantity estimates ............................... (34,549) (12,706) (47,255)
Changes in production rates and other ........................ (10,957) (3,889) (14,846)
----------- --------- -----------
Change in Standardized Measure ............................... $(1,087,251) $ 64,192 $(1,023,059)
=========== ========= ===========
(1) Net of hedging revenue of $15.8 million on United States production.
YEAR ENDED DECEMBER 31, 2000
-------------------------------------------------
UNITED
STATES CANADA TOTAL
------------ ---------- ----------
(IN THOUSANDS)
Gas and oil sales, net of production costs .................... $ (169,375) $ -- $ (169,375)
Net changes in anticipated prices and production cost ......... 1,535,058 -- 1,535,058
Extensions and discoveries, less related costs ................ 251,410 -- 251,410
Changes in estimated future development costs ................. 8,831 -- 8,831
Previously estimated development costs incurred ............... 26,084 -- 26,084
Net change in income taxes .................................... (652,306) -- (652,306)
Purchase of minerals in place ................................. 18,917 -- 18,917
Sales of minerals in place .................................... (679) -- (679)
Accretion of discount ......................................... 39,343 -- 39,343
Revision of quantity estimates ................................ 198,625 -- 198,625
Changes in production rates and other ......................... (113,712) -- (113,712)
---------- -------- ----------
Change in Standardized Measure ................................ $1,142,196 $ -- $1,142,196
========== ======== ==========
YEAR ENDED DECEMBER 31, 1999
-----------------------------------------------
UNITED
STATES CANADA TOTAL
------------ ---------- ----------
(IN THOUSANDS)
Gas and oil sales, net of production costs .................... $ (76,052) $ -- $ (76,052)
Net changes in anticipated prices and production cost ......... 32,745 -- 32,745
Extensions and discoveries, less related costs ................ 31,796 -- 31,796
Changes in estimated future development costs ................. 21,246 -- 21,246
Previously estimated development costs incurred ............... 1,435 -- 1,435
Net change in income taxes .................................... (27,561) -- (27,561)
Purchase of minerals in place ................................. 98,419 -- 98,419
Sales of minerals in place .................................... (1,207) -- (1,207)
Accretion of discount ......................................... 25,402 -- 25,402
Revision of quantity estimates ................................ 369 -- 369
Changes in production rates and other ......................... 5,250 -- 5,250
---------- -------- ----------
Change in Standardized Measure ................................ $ 111,842 $ -- $ 111,842
========== ======== ==========
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.
51
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.
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.
(Incorporated by reference to Exhibit 2.2 in the
Registrant's Form 10-K Report for the fiscal year ended
December 31, 2000, and filed with the Securities and
Exchange Commission on March 13, 2001)
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)
3.2 -- Amended and Restated Bylaws, dated May 10, 2001.
(Incorporated by reference to Exhibit 3.1 in the
Registrant's Form 10-Q, for the quarterly period ended
March 31, 2001, and filed with the Securities and Exchange
Commission on May 14, 2001)
4.1 -- First Amended and Restated Rights Agreement dated March
1, 2001 between the Registrant and EquiServe Trust
Company, N.A. (Incorporated by reference to Exhibit 4.2 in
the Registrant's Form 10-K Report for the fiscal year
ended December 31, 2000, and filed with the Securities and
Exchange Commission on March 13, 2001)
10.1 -- 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)
52
10.2 -- U.S. Revolving Credit Agreement dated March 20, 2001.
(Incorporated by reference to Exhibit 10.2 in the
Registrant's Form 10-Q Report for the quarterly period
ended March 31, 2001 and filed with the Securities and
Exchange Commission on May 14, 2001)
10.3 -- Canadian Revolving Credit Agreement dated March 20,
2001. (Incorporated by reference to Exhibit 10.3 in the
Registrant's Form 10-Q Report for the quarterly period
ended March 31, 2001 and filed with the Securities and
Exchange Commission on May 14, 2001)
10.4 -- Canadian Term Credit Agreement dated March 20, 2001.
(Incorporated by reference to Exhibit 10.4 in the
Registrant's Form 10-Q Report for the quarterly period
ended March 31, 2001 and filed with the Securities and
Exchange Commission on May 14, 2001)
10.5 -- Credit Agreement dated June 30, 2000, among the
Registrant, The Chase Manhattan Bank and the other lenders
parties thereto. (Incorporated by reference to Exhibit
10.1 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)
10.6 -- 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)
10.7 -- First Amendment, dated October 19, 1998, to the Credit
Agreement, dated April 17, 1998. (Incorporated by
reference to Exhibit 10.1 in the Registrant's Form 10-Q
Report for the quarterly period ended September 30, 1998,
and filed with the Securities and Exchange Commission on
November 13, 1998)
10.8 -- 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)
10.9 -- 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)
Executive Compensation Plans and Arrangements (Exhibits 10.10 through 10.23):
10.10 -- 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)
10.11 -- 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)
53
10.12 -- Employment Agreement dated May 3, 1999 between the
Registrant and James D. Lightner. (Incorporated by
reference to Exhibit 10.3 in the Registrant's Form 8-K
Report dated July 19, 1999, and filed with the Securities
and Exchange Commission on July 19, 1999)
10.13 -- 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)
10.14 -- First Amendment to Tom Brown, Inc. Severance Plan dated
May 10, 2001. (Incorporated by reference to Exhibit 10.5
in the Registrant's Form 10-Q Report for the quarterly
period ended March 31, 2001 and filed with the Securities
and Exchange Commission on May 14, 2001)
10.15 -- 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)
10.16 -- First Amendment to Severance Agreement dated May 10,
2001. (Incorporated by reference to Exhibit 10.8 in the
Registrant's Form 10-Q Report for the quarterly period
ended March 31, 2001 and filed with the Securities and
Exchange Commission on May 14, 2001)
10.17* -- 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.
10.18 -- Deferred Compensation Plan dated March 1, 2001.
(Incorporated by reference to Exhibit 10.22 in the
Registrant's Form 10-K Report for the fiscal year ended
December 31, 2000, and filed with the Securities and
Exchange Commission on March 13, 2001)
10.19 -- 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)
10.20 -- Amendment to Tom Brown, Inc. 1999 Long-Term Incentive
Plan dated May 10, 2001. (Incorporated by reference to
Exhibit 10.6 in the Registrant's Form 10-Q Report for the
quarterly period ended March 31, 2001 and filed with the
Securities and Exchange Commission on May 14, 2001)
10.21 -- Amended and Restated 1993 Stock Option Plan.
(Incorporated by reference to Exhibit 10.1 in the
Registrant's Form 10-Q Report for the quarterly period
ended March 31, 2001 and filed with the Securities and
54
Exchange Commission on May 14, 2001)
10.22 -- Amendment to Tom Brown, Inc. Amended and Restated 1993 Stock
Option Plan dated May 10, 2001. (Incorporated by reference to
Exhibit 10.7 in the Registrant's Form 10-Q Report for the quarterly
period ended March 31, 2001 and filed with the Securities and
Exchange Commission on May 14, 2001)
10.23 -- 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)
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 November 8,
2001.
Form 8-K Item 7. 2002 Financial Model Estimates filed on February
28, 2002.
55
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
TOM BROWN, INC.
By /s/ JAMES B. WALLACE
--------------------
James B. Wallace
Chairman of the Board of Directors
Date: March 19, 2002
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 19, 2002
- -------------------------------------------
James B. Wallace
/s/ JAMES D. LIGHTNER President, Chief March 19, 2002
- ------------------------------------------- Executive Officer and Director
James D. Lightner
/s/ DANIEL G. BLANCHARD Executive Vice President, Chief March 19, 2002
- ------------------------------------------- Financial Officer and Treasurer
Daniel G. Blanchard
/s/ RICHARD L. SATRE Controller March 19, 2002
- -------------------------------------------
Richard L. Satre
/s/ THOMAS C. BROWN Director March 19, 2002
- -------------------------------------------
Thomas C. Brown
/s/ DAVID M. CARMICHAEL Director March 19, 2002
- -------------------------------------------
David M. Carmichael
/s/ HENRY GROPPE Director March 19, 2002
- -------------------------------------------
Henry Groppe
/s/ EDWARD W. LEBARON, JR. Director March 19, 2002
- -------------------------------------------
Edward S. LeBaron, Jr.
/s/ ROBERT H. WHILDEN, JR. Director March 19, 2002
- -------------------------------------------
Robert H. Whilden, Jr.
/s/ WAYNE W. MURDY Director March 19, 2002
- -------------------------------------------
Wayne W. Murdy
56
EXHIBIT INDEX
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.
(Incorporated by reference to Exhibit 2.2 in the
Registrant's Form 10-K Report for the fiscal year ended
December 31, 2000, and filed with the Securities and
Exchange Commission on March 13, 2001)
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)
3.2 -- Amended and Restated Bylaws, dated May 10, 2001.
(Incorporated by reference to Exhibit 3.1 in the
Registrant's Form 10-Q, for the quarterly period ended
March 31, 2001, and filed with the Securities and Exchange
Commission on May 14, 2001)
4.1 -- First Amended and Restated Rights Agreement dated March
1, 2001 between the Registrant and EquiServe Trust
Company, N.A. (Incorporated by reference to Exhibit 4.2 in
the Registrant's Form 10-K Report for the fiscal year
ended December 31, 2000, and filed with the Securities and
Exchange Commission on March 13, 2001)
10.1 -- 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)
57
10.2 -- U.S. Revolving Credit Agreement dated March 20, 2001.
(Incorporated by reference to Exhibit 10.2 in the
Registrant's Form 10-Q Report for the quarterly period
ended March 31, 2001 and filed with the Securities and
Exchange Commission on May 14, 2001)
10.3 -- Canadian Revolving Credit Agreement dated March 20,
2001. (Incorporated by reference to Exhibit 10.3 in the
Registrant's Form 10-Q Report for the quarterly period
ended March 31, 2001 and filed with the Securities and
Exchange Commission on May 14, 2001)
10.4 -- Canadian Term Credit Agreement dated March 20, 2001.
(Incorporated by reference to Exhibit 10.4 in the
Registrant's Form 10-Q Report for the quarterly period
ended March 31, 2001 and filed with the Securities and
Exchange Commission on May 14, 2001)
10.5 -- Credit Agreement dated June 30, 2000, among the
Registrant, The Chase Manhattan Bank and the other lenders
parties thereto. (Incorporated by reference to Exhibit
10.1 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)
10.6 -- 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)
10.7 -- First Amendment, dated October 19, 1998, to the Credit
Agreement, dated April 17, 1998. (Incorporated by
reference to Exhibit 10.1 in the Registrant's Form 10-Q
Report for the quarterly period ended September 30, 1998,
and filed with the Securities and Exchange Commission on
November 13, 1998)
10.8 -- 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)
10.9 -- 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)
Executive Compensation Plans and Arrangements (Exhibits 10.10 through 10.23):
10.10 -- 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)
10.11 -- 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)
58
10.12 -- Employment Agreement dated May 3, 1999 between the
Registrant and James D. Lightner. (Incorporated by
reference to Exhibit 10.3 in the Registrant's Form 8-K
Report dated July 19, 1999, and filed with the Securities
and Exchange Commission on July 19, 1999)
10.13 -- 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)
10.14 -- First Amendment to Tom Brown, Inc. Severance Plan dated
May 10, 2001. (Incorporated by reference to Exhibit 10.5
in the Registrant's Form 10-Q Report for the quarterly
period ended March 31, 2001 and filed with the Securities
and Exchange Commission on May 14, 2001)
10.15 -- 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)
10.16 -- First Amendment to Severance Agreement dated May 10,
2001. (Incorporated by reference to Exhibit 10.8 in the
Registrant's Form 10-Q Report for the quarterly period
ended March 31, 2001 and filed with the Securities and
Exchange Commission on May 14, 2001)
10.17* -- 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.
10.18 -- Deferred Compensation Plan dated March 1, 2001.
(Incorporated by reference to Exhibit 10.22 in the
Registrant's Form 10-K Report for the fiscal year ended
December 31, 2000, and filed with the Securities and
Exchange Commission on March 13, 2001)
10.19 -- 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)
10.20 -- Amendment to Tom Brown, Inc. 1999 Long-Term Incentive
Plan dated May 10, 2001. (Incorporated by reference to
Exhibit 10.6 in the Registrant's Form 10-Q Report for the
quarterly period ended March 31, 2001 and filed with the
Securities and Exchange Commission on May 14, 2001)
10.21 -- Amended and Restated 1993 Stock Option Plan.
(Incorporated by reference to Exhibit 10.1 in the
Registrant's Form 10-Q Report for the quarterly period
ended March 31, 2001 and filed with the Securities and
59
Exchange Commission on May 14, 2001)
10.22 -- Amendment to Tom Brown, Inc. Amended and Restated 1993
Stock Option Plan dated May 10, 2001. (Incorporated by
reference to Exhibit 10.7 in the Registrant's Form 10-Q
Report for the quarterly period ended March 31, 2001 and
filed with the Securities and Exchange Commission on May
14, 2001)
10.23 -- 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)
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 November 8,
2001.
Form 8-K Item 7. 2002 Financial Model Estimates filed on February
28, 2002.
60