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EXHIBIT 99.1

2001 FINANCIAL MODEL ESTIMATES

This document is intended to provide information and estimates to permit
preparation of models of Tom Brown, Inc. ("Tom Brown" or the "Company") for
2001. This information constitutes the Company's current estimates based on a
number of assumptions. The estimates are based on the Company's historical
operating performance and trends, estimates of oil and gas reserves at December
31, 2000, the Company's planned capital and operating budget for 2001 and
current expectations for oil and gas production, gas trading activities, hedged
positions, tax rates and expenses. The following estimates reflect our view of
continuing operations only. The 2001 estimates were prepared assuming that
demand, curtailment, productibility and general market conditions for oil and
gas will be substantially similar to those experienced during 2000. We do not
account for the potential impact of acquisitions or divestitures except for the
pending Stellarton Energy acquisition. We caution you that the estimates set
forth below are given as of the date hereof only and are based on currently
available information. We are not assuming any obligation to update any
information contained herein.

All of the estimates and assumptions included in this document are
forward-looking statements within the meaning of Section 21E of the Securities
Exchange Act of 1934. We believe that the forward-looking statements are based
on reasonable assumptions but no assurances can be given that our expectations
will be met. Actual results may differ materially due to a number of risks and
uncertainties, including but not limited to:

o COMMODITY PRICE CHANGES, INCLUDING LOCAL AND REGIONAL VARIATIONS;

o RISKS AND PROBLEMS INCIDENT TO THE DRILLING AND OPERATION OF OIL
AND GAS WELLS, SUCH AS DRILLING DIFFICULTIES OR DELAYS, WELL
EXPLOSIONS OR OTHER DISASTERS, ENVIRONMENTAL RISKS, AND LACK OF
CONTROL OVER TIMING OF EXPENDITURES ON THIRD-PARTY OPERATED
PROPERTIES;

o CHANGES IN PRODUCTION AND DEVELOPMENT COSTS;

o CHANGES IN DRILLING SUCCESS RATES;

o CHANGES IN LAWS AND OTHER REGULATORY ACTIONS;

o CHANGES IN EXCHANGE RATES;

o RISKS INCIDENT TO HEDGING ACTIVITIES;

o CHANGES IN INTEREST RATES AND CAPITAL MARKET CONDITIONS;

o CHANGES IN GENERAL ECONOMIC CONDITIONS;

o COMPETITION FROM OTHERS IN THE ENERGY INDUSTRY;

o THE UNCERTAINTY INHERENT IN ESTIMATES OF OIL AND GAS RESERVES AND
PRODUCTION RATES;

o UNUSUAL OR INFREQUENT ITEMS THAT ARE NOT SUSCEPTIBLE TO
ESTIMATES; AND

For additional information concerning important factors that may cause
actual results to differ materially from those estimated, see the Company's Form
10-K for the year ended December 31, 1999. Unless otherwise noted, all of the
following dollar amounts are expressed in U.S. dollars.

While oil and gas prices have been at or near multi-year highs in 2000,
there can be no assurance that current price levels will continue. Oil and gas
prices have fluctuated significantly in recent years in response to numerous
economic, political and environmental factors and we expect that commodity
prices will continue to fluctuate significantly in the future. Changes in
commodity prices could significantly affect our expected operating results. In
addition to directly effecting revenues, price changes can affect expected
production because production estimates necessarily assume that oil and gas can
profitably be produced at the assumed pricing levels.

PRODUCTION ESTIMATES

First Quarter 2001(1) Annual 2001(1)
-------------------------------- -------------------------------
U.S. Canada Total U.S. Canada Total
-------- ---------- ---------- -------- -------- ----------

Natural gas (Mcfpd) 142,000 18,000 160,000 151,000 25,000 176,000
Natural gas liquids (Bonglpd) 2,800 390 3,190 2,900 530 3,430
Oil (Bopd) 2,000 400 2,400 2,000 450 2,450
-------- ---------- ---------- -------- -------- ----------
Total equivalent (Mcfepd) 170,800 22,700 193,500 180,400 30,880 211,280

Total production (Mmcfe) 15,400 2,000 17,400 65,800 11,300 77,100

(1) These estimates approximate the mid-point of the range of the Company's
estimates of production. Actual results may differ and important assumptions are
included in the narrative.

The estimate of 151,000 Mcfpd for 2001 U.S. gas production is an
increase of approximately nine percent from 2000. The U.S. oil and natural gas
liquids production of 4,900 barrels per day is flat with 2000. The estimated
production from Canada is dependant upon the closing of the Stellarton Energy
acquisition in mid-January 2001. Tom Brown signed a definitive agreement to
acquire Stellarton on December 13, 2000. Tom Brown initiated an all cash tender
offer of C$5.00 per Stellarton share on December 20, 2000. The acquisition has
been unanimously approved by the Boards of Directors of Tom Brown and
Stellarton. The Company's combined total oil and gas production of 77,100 Mmcfe
is approximately 25% higher than 2000.

GAS PRICE HEDGES

The Company has put in place hedges in the form of costless collars
covering an average of 58,000 MMBtu/d of its U.S. production for the period of
January through December 2001. In addition, basis hedges have been entered into
to correlate the NYMEX hedges back to the index delivery point. The following
table provides a quarterly summary of the volumes, collar range, and basis:

Tom Brown, Inc. collars:

Period 2001 Volume Floor Ceiling NYMEX
(Quarter) (MMBtu/d) $/MMbtu $/MMBtu Basis Lock
- --------- --------- ------- ------- ----------

First 70,000 $ 6.60 $ 9.06 $(0.05)
Second 63,000 4.32 7.05 (0.28)
Third 60,000 4.03 6.73 (0.28)
Fourth 40,000 4.14 6.76 (0.27)
--------- ------- ------- ------
Year average 58,000 $ 4.89 $ 7.51 $(0.21)

Stellarton Energy Hedges:

Fixed Well
Period 2001 Volume Head Price
(Quarter) (MMBtu/d) ($/ MMBtu)(a)
- ----------- --------- -------------

First 13,600 $4.14
Second 9,300 2.57
Third 9,300 2.57
Fourth 7,600 2.27
----- -----
Year average 9,850 $3.04

a) Assumes exchange ratio of C$0.66= US$1.00

Depending on various circumstances, the Company may periodically enter
into additional financial derivatives that would hedge expected crude oil and
natural gas production.

MARKETING, GATHERING, PROCESSING MARGIN

The Company's gathering and processing margin is generated from the
assets distributed out of the Wildhorse joint venture in 2000 and the helium
revenue from the Lisbon plant in the Paradox basin. The Company's marketing
group earns a margin from the sale of Tom Brown's working interest gas
production and the purchase and resale of third party gas. The Company is
currently in the process of selling certain non-strategic gathering and
processing assets. Excluding the effect of the potential asset sales the Company
expects the marketing, gathering and processing margin to average $2.5 to $3.0
million per quarter in 2001.

OIL AND GAS PRODUCTION COSTS

The Company's lifting cost are expected to average $0.41-$0.43 per Mcfe
in the U.S. and $0.51-$0.53 per Mcfe in Canada. Production taxes are estimated
to average 10 percent of U.S. wellhead sales revenue.

EXPLORATION COSTS/IMPAIRMENT OF LEASEHOLD COST

Exploration expense can fluctuate significantly quarter to quarter,
depending on the timing of exploratory expenditures and the recognition of wells
as either productive or dry holes. The forecasting of these expenditures are
inherently inaccurate. Based upon planned activity levels we estimate U.S
exploration cost in the range of $30-$35 million for 2001. The estimate of
Canadian exploration cost is expected to be $7$-$9 million for 2001. The Company
is also budgeting $1.2 million per quarter for amortization of impairment of
leasehold cost.

DEPRECIATION, DEPLETION AND AMORTIZATION

Depreciation, depletion and amortization (DD&A) rate for the Company's
U.S. operations is expected to be $0.80-$0.85 per Mcfe for 2001. This estimate
may be revised following the preparation of the December 31, 2000 reserve
report. The DD&A rate for the Company's Canadian operations will likely range
from $1.60-$1.75 per Mcfe. The rate is comprised of approximately $1.15 per Mcfe
from the purchase of the Stellarton assets and $0.45-$0.60 per Mcfe from the
step-up in the property basis for deferred taxes. The higher DD&A rate for the
deferred tax step-up is offset by deferred tax benefit in the income tax
provision (see Provision for Income Taxes below).

GENERAL AND ADMINISTRATIVE EXPENSE

The Company expects its U.S. general and administrative (G&A) expense
per Mcfe to be in the range of $0.20-$0.22. G&A expense for its Canadian
operations is expected to be in the range of $0.29-$0.32 per Mcfe.

INTEREST EXPENSE

The Company is currently negotiating a new three year credit facility
as part of the Stellarton acquisition. As of September 30, 2000 the Company had
$67 million drawn under its existing facility. December 31, 2000 debt, pro forma
for the Stellarton acquisition, is approximately $150 million. Based upon
current LIBOR rates the Company is assuming interest rates will average
8.0%-9.0% for 2001.

PROVISION FOR INCOME TAXES

Provision for income taxes for its U.S. earnings is expected to be
approximately 38% of income before taxes. Of the total tax provision, 20% is
estimated to be current cash taxes.

The provision for income taxes for its Canadian earnings is estimated
to be approximately 45% of income before taxes. The current tax provision can be
estimated by multiplying pre-tax earnings by approximately 110%-130%. Current
income tax provision will be offset by the deferred tax benefit from the
property basis step-up. The current tax provision and deferred tax benefit
should combine to a total tax provision of approximately 45% of pre-tax
earnings.

2001 CAPITAL BUDGET

Preliminary 2001 capital expenditure is expected to be in the range of
$150-$165 million for U.S. exploration and development spending. The expected
2001 capital budget represents a 40-55% increase over 2000 (for the period
excluding acquisitions).

The preliminary estimate of 2001 Canadian exploration and development
expenditures is expected in the range of $35-$40 million (excluding the cost to
acquire Stellarton of approximately $95 million).

The spending will be funded out of the Company's discretionary cash
flow based on anticipated commodity prices and is subject to change if market
conditions shift or new opportunities are identified.