SECURITIES AND EXCHANGE
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report (Date of earliest event reported) November 12, 2002
Tom Brown, Inc.
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(Exact name of registrant as specified in its charter)
DELAWARE 001-31308 95-1949781
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(STATE OR OTHER JURISDICTION OF (COMMISSION FILE (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) NUMBER) IDENTIFICATION NO.)
555 SEVENTEENTH STREET, SUITE 1850
DENVER, COLORADO 80202
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(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
(303) 260-5000
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(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
NOT APPLICABLE
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(FORMER NAME, FORMER ADDRESS AND FORMER FISCAL YEAR,
IF CHANGED SINCE LAST REPORT)
ITEM 5. OTHER EVENTS
Tom Brown, Inc. press release dated November 12, 2002, entitled "TOM BROWN,
INC. REPORTS THIRD QUARTER 2002 FINANCIAL AND OPERATING RESULTS"
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
Date: November 13, 2002 Tom Brown, Inc.
By: /s/ Daniel G. Blanchard
------------------------------------
Daniel G. Blanchard
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
By: /s/ Richard L. Satre
------------------------------------
Richard L.Satre
Controller
(Principal Accounting Officer)
ITEM 5. OTHER EVENTS
The Company issued the following press release:
TOM BROWN, INC.
REPORTS THIRD QUARTER 2002 FINANCIAL AND OPERATING RESULTS
DENVER, NOVEMBER 12, 2002 - TOM BROWN, INC. (NYSE: TBI) today reported
results from operations for the third quarter ended September 30, 2002.
For the three months ended September 30, 2002, the Company reported a net
loss of $1.8 million or $0.05 per share (all per share amounts are on a diluted
basis) as compared to net income of $5.8 million or $0.14 per share during the
same period of the prior year. The decrease in current quarter earnings is a
result of a 33% decrease in realized gas price and the previously announced $6.2
million pre-tax charge ($4.1 million after tax) to establish an allowance for a
delinquent receivable from the Company's previous purchaser of its natural gas
liquids in the Paradox Basin of Colorado and Utah. Excluding the cumulative
effect of changes in accounting principles, the Company reported net income for
the nine months ended September 30, 2002, of $2.6 million or $0.06 per share as
compared to net income of $67.4 million or $1.68 per share in the corresponding
period of 2001.
Discretionary cash flow for the third quarter of 2002 totaled $23.0
million, or $0.59 per share, a decrease of 54% from the $50.1 million, or $1.25
per share, in the corresponding period of 2001. For the nine months ended
September 30, 2002 discretionary cash flow from operations totaled $86.3 million
or $2.13 per share as compared to $186.2 million, or $4.62 per share in the same
period in 2001.
"Tom Brown is performing strongly in the middle of a very challenging price
environment for Rocky Mountain natural gas. We grew our production volumes 16%
year over year through the third quarter by efficient execution of our drilling
programs. We have reduced our lease operating expense by 14% per unit volume and
have added to our exploration portfolio in all our core areas ," said Jim
Lightner, Tom Brown Inc.'s Chairman, CEO and President.
"In response to extremely low Rockies gas prices we curtailed production of
up to 20 Mmcfpd in September and October and significantly cut back on our
development drilling programs throughout the Company due to lower cash flows and
internal capital efficiency targets. Our production growth of 10%-12% this year
is front-end loaded and demonstrates the quality and depth of our drilling
portfolio as long as gas prices justify pursuing growth through the drill bit.
We are convinced that a higher natural gas price plateau will be realized in the
near future and are confident that our people, large acreage position and
extensive drilling portfolio have positioned TBI very well for the future."
The following table summarizes the Company's production and commodity price
realizations for the 2002 and 2001 periods ended September 30:
THREE MONTHS ENDED NINE MONTHS ENDED
---------------------------------- ------------------------------------
PRODUCTION 9/30/02 9/30/01 CHANGE 9/30/02 9/30/01 CHANGE
---------- ------- ------- ------ ------- ------- ------
Natural gas (Bcf) 17.9 15.8 13% 54.5 46.1 18%
Oil (MBbls) 187 211 (11)% 642 657 (2)%
NGLs (MBbls) 356 342 4% 1,081 947 14%
Equivalent (Bcfe) 21.1 19.2 10% 64.9 55.8 16%
REALIZED PRICES
---------------
Natural gas ($/Mcf) 1.77 2.64 (33)% 2.01 4.30 (53)%
Oil ($/Bbl) 26.05 24.30 4% 22.85 25.47 (10)%
NGLs ($/Bbl) 11.80 12.27 (4)% 10.44 15.43 (32)%
The Company's production in the third quarter of 2002 averaged 229.8
million cubic feet equivalent per day (Mmcfepd), a 10% increase over the same
quarter in 2001. Daily production decreased sequentially from the second to the
third quarter of 2002 by 15.1 MMcfepd. The sequential decrease in production is
a result of the Company's curtailment of natural gas production in the Rockies
and also from decreased development drilling activity because of low realized
natural gas prices in the region. Gas and oil sales for the three months ended
September 30, 2002 totaled $40.7 million, a decrease of $10.4 million or 20%
less than the prior year's comparable period. The decrease in gas and oil sales
is a result of lower realized commodity prices partially offset by higher
production.
Operating expense for the current quarter and the comparable prior year's
quarter averaged $0.38 per Mcfe and $0.44 per Mcfe, respectively, while
production taxes of $0.14 per Mcfe were $0.05 per Mcfe higher than in the
corresponding period of the prior year. The increase in production taxes per
unit volume in the third quarter 2002 relative to the 2001 third quarter is a
result of a cash refund of prior years' taxes credited to the third quarter
2001. Combined cash costs (operating, production taxes, interest expense and
general and administrative--excluding non-cash costs) totaled $0.79 per Mcfe in
the third quarter of 2002, $0.08 per Mcfe lower than in the prior year's
comparable period. Net cash margin totaled $1.14 per Mcfe in the most recently
completed quarter as compared to $1.80 per Mcfe in the prior year's comparable
period.
Tom Brown has natural gas hedges in the form of costless collars and swaps
in place at various pipeline delivery points. The costless collars and swaps are
summarized below:
NATURAL GAS COLLARS NATURAL GAS SWAPS
-------------------------------- -------------------------------
VOLUME IN WEIGHTED AVERAGE VOLUME IN WEIGHTED AVERAGE
PERIOD MMBTU/D FLOOR/CEILING MMBTU/D SWAP PRICE
------ --------- ---------------- --------- ----------------
Fourth quarter 2002 18,000 $2.98/$4.32 89,000 $2.65
2003 15,000 $3.13/$4.57 53,000 $3.04
The Company's marketing, gathering and processing margins totaled $5.7
million in the most recently completed quarter compared to $4.1 million in the
previous corresponding period. Marketing margin for the third quarter of 2002
totaled $2.6 million as compared to $0.6 million in the prior year's third
quarter. The gathering and processing margin was $3.1 million for the third
quarter of this year as compared to $3.4 million for the previous year's third
quarter.
The Company also entered into certain financial instruments to lock in a
margin on 15,000 Mmbtu/d of gas moved under its firm transportation to the Mid
Continent region during the June to October 2002 contract periods. The net
margin, which the Company locked in, is approximately $0.29/Mmbtu through the
contract period. However, the financial instruments are considered trading
derivatives under SFAS No. 133. Therefore, the cash paid for derivatives of $1.4
million for the nine months ended September 30, 2002 is offset by the benefit
from the price differential on the 15,000 Mmbtu/d transported on the firm
transportation. The benefit from the price differential on the 15,000 Mmbtu/d
transported on the firm transportation of $1.9 million is included in marketing
and trading which, net of the cash settlement payment on the financial
instruments, results in a $0.29/Mmbtu margin.
THIRD QUARTER 2002 EXPLORATION AND DEVELOPMENT PROGRAM
For the nine months ended September 30, 2002, the Company drilled or
participated in a total of 62 wells in the U.S. and 11 in Canada. Of the 62
wells drilled in the U.S., at quarter end 43 wells had been completed, 13 wells
were in the process of being completed and six were dry holes. At quarter-end,
four wells were drilling in the U.S. Of the 11 wells drilled in Canada, at
quarter end six wells had been completed, four were in the process of being
completed and one was abandoned.
WIND RIVER BASIN
In the nine months ended September 30, 2002, the Company drilled 16 wells
and at quarter end, 15 were completed and one was in the process of being
completed. The majority of the drilling activity was in the Pavillion field
where 12 successful wells were drilled. The remainder of the drilling was in the
Muddy Ridge field where Tom Brown drilled four wells. The Company produced an
average of 60.6 Mmcfepd net for the nine months ended September 30, 2002 from
the Wind River Basin, an increase of 27% over the comparable period of the prior
year.
PICEANCE BASIN
The Company drilled 18 wells in the Piceance Basin during the first three
quarters of 2002. At quarter end 12 of the wells had been completed, five were
in the process of being completed and one well was abandoned. The majority of
the drilling occurred in the Company's White River Dome field (TBI 100% working
interest) where 14 of the wells were drilled. At quarter end 12 wells had been
completed, one was being completed, and one well was abandoned. The Company
produced an average of 33.4 Mmcfepd net for the nine months ended September 30,
2002 from the Piceance Basin, an increase of 56% over the comparable period of
the prior year.
PARADOX BASIN
In the first nine months of 2002, the Company drilled four wells with a 75%
success rate in the Paradox Basin at the Company's Andy's Mesa field. The
Company produced an average of 45.8 Mmcfepd net for the nine months ended
September 30, 2002 from the Paradox Basin, an increase of 17% over the
comparable period of the prior year.
SOUTHERN REGION (TEXAS AND LOUISIANA)
In the first nine months of the 2002, the Company drilled or participated
in 19 wells in Texas and was drilling two wells at quarter-end. The Company
produced an average of 49.8 Mmcfepd net for the nine months ended September 30,
2002 from the Southern Region, an increase of 15% over the comparable period of
the prior year.
In the Marathon-operated Mimms Creek field (TBI 55% working interest), the
Company participated in eight successful Bossier sand wells out of nine in the
first three quarters of 2002. The wells completed in 2002 have had an average
initial gross production rate of 3.7 Mmcfepd. As a result of its successful 2002
drilling program, the Company's average net daily production for the third
quarter of 2002 from the Mimms Creek field has grown to 12 Mmcfepd, an increase
of 65% from the comparable period of 2001.
In the Deep Valley project area in the Permian Basin, the Company has
reached total measured depth of 20,115 feet (with a 3,215 foot lateral in the
Devonian formation) at the Beefmaster #1H (TBI 50% working interest). The
Company is planning to fracture stimulate the lateral. The Company continues to
evaluate the Moore-Gilmore #1H (TBI 100% working interest), and expects to
fracture stimulate the heel portion of horizontal lateral in the Devonian
section.
CANADA
In the first nine months of 2002, the Company drilled 11 wells in Canada
primarily in the Carrot Creek and Edson fields. In Canada, the Company produced
an average of 24.4 Mmcfepd net for the nine months ended September 30, 2002, an
increase of 2% over the comparable period of the prior year.
OUTLOOK FOR 2002
The following statements provide a summary of certain estimates based on
current expectations for the fourth quarter and full-year of 2002 (the Company
will also include this forward looking guidance in a Form 8-K filing). Tom
Brown's exploration and production capital expenditures (excluding acquisitions)
for the first three quarters of 2002 totaled $114.2 million. For the full-year
2002, the Company is projecting its exploration and development capital
expenditures at approximately $145 million which is at the lower end of its
prior guidance of $145-$155 million. The capital expenditures break down as
follows: approximately 69% for development activities, 8% for land acquisitions
and 23% for exploration.
Based upon this anticipated level of spending, Tom Brown expects 2002
production to increase approximately 10%-12% from 2001. The following table
summarizes the mid-point values of the estimated production levels for the
fourth quarter and full-year 2002.
ESTIMATED FOURTH QUARTER 2002 ESTIMATED FULL YEAR 2002
--------------------------------- ---------------------------------
U.S. CANADA TOTAL U.S. CANADA TOTAL
------- ------ ------- ------- ------ -------
Natural gas (Mcfpd) 172,000 15,500 187,500 179,000 17,300 196,300
Natural gas liquids (Bonglpd) 3,100 550 3,650 3,350 530 3,880
Oil (Bopd) 1,300 450 1,750 1,650 550 2,200
------- ------ ------- ------- ------ -------
Total equivalent (Mcfepd) 198,400 21,500 219,900 209,000 23,780 232,780
Total production (Mmcfe) 18,250 1,980 20,230 76,300 8,700 85,000
The Company's marketing group earns a margin from the purchase and resale
of natural gas. In addition, the Company owns and operates certain mid-stream
gathering and processing assets. The Company expects the marketing, gathering
and processing margin to average $3.0-$3.5 million for the fourth quarter of
2002.
Preliminary estimates for exploration expense are $8-$10 million for the
fourth quarter of 2002 and $23-$25 million for the entire year, including
estimated dry hole expense. Actual dry hole expense could differ based on timing
and results of wells. Other operating expenses for the fourth quarter of 2002
are expected to fall within the ranges summarized below:
OPERATING COSTS ($)/Mcfe:
Lease operating expense 0.37 - 0.39
General and administrative expense 0.21 - 0.23
Interest expense and other 0.10 - 0.11
Depreciation, depletion and amortization 1.05 - 1.07
Production taxes (% of oil and gas revenues) 8.0% - 9.0%
Provision for income taxes is expected to be approximately 35% of pre-tax
earnings. Less than one-quarter of the total tax provision is projected to
represent taxes currently payable.
The Company's management will hold a conference call tomorrow, Wednesday,
November 13, 2002 at 12:00 p.m. Mountain Standard Time to review the third
quarter 2002 results. The dial-in number to participate in the call is
800-399-0117 (U.S.) or 706-679-3393 (International), or the call can be accessed
live in a listen-only mode by following the link from the Company's website
www.tombrown.com.
TOM BROWN, INC. IS A DENVER, COLORADO BASED INDEPENDENT ENERGY COMPANY
ENGAGED IN THE EXPLORATION FOR, AND THE ACQUISITION, DEVELOPMENT, PRODUCTION AND
MARKETING OF, NATURAL GAS, NATURAL GAS LIQUIDS AND CRUDE OIL IN NORTH AMERICA.
THE COMPANY'S COMMON STOCK IS TRADED ON THE NEW YORK STOCK EXCHANGE UNDER THE
SYMBOL TBI.
This news release includes forward-looking statements within the meaning of
section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. These statements are based on certain assumptions and
analyses made by the Company in light of its experience, on general economic and
business conditions and expected future developments, many of which are beyond
the control of the Company. Important factors that could cause actual results to
differ materially from those in the forward-looking statements herein include
the timing and extent of changes in commodity prices for oil and gas,
environmental risks, operating risks, risks related to exploration and
development, the ability of the Company to meet its stated business goals and
other risk factors as described in the Company's 2001 Annual Report and Form
10-K as filed with the Securities and Exchange Commission. As a result of those
factors, the Company's actual results may differ materially from those indicated
in or implied by such forward-looking statements.
Contact: Tom Brown, Inc.
Mark Burford
Director of Investor Relations
(303) 260-5146
# # # #
TOM BROWN, INC. AND SUBSIDIARIES
Consolidated Summary Statement of Operations (Unaudited)
Three and Nine Months ended September 30, 2002 and 2001
Three months ended Nine months ended
September 30, September 30,
------------------------- -------------------------
2002 2001 2002 2001
--------- --------- --------- ---------
(In thousands except per share amounts)
Revenues:
Gas, oil and natural gas liquids sales $ 40,749 $ 51,192 $ 135,679 $ 229,699
Gathering and processing 4,459 4,480 14,448 19,073
Marketing and trading, net 2,643 638 3,335 2,068
Drilling 5,036 4,111 9,617 10,668
Gain on sale of property -- -- 4,004 10,078
Change in derivative fair value 299 (1,950) (1,042) (2,953)
Cash (paid) received on derivatives (1,126) 1,032 (1,438) 3,904
Loss on marketable security -- -- (600) --
Interest income and other 105 (251) 431 785
--------- --------- --------- ---------
Total revenues $ 52,165 $ 59,252 $ 164,434 $ 273,322
--------- --------- --------- ---------
Costs and expenses:
Gas and oil production $ 7,999 $ 8,462 $ 24,318 $ 24,308
Taxes on gas and oil production 3,029 1,661 11,829 18,106
Gathering and processing costs 1,356 1,037 4,580 10,202
Drilling operations 4,354 2,984 9,293 8,417
Exploration costs 4,150 10,490 15,334 24,621
Impairments of leasehold costs 1,392 1,200 4,173 3,600
General and administrative 3,812 4,671 13,177 18,518
Depreciation, depletion and amortization 22,823 17,973 68,846 52,674
Bad debts 6,262 42 6,478 114
Interest expense and other 1,832 1,936 5,737 5,916
--------- --------- --------- ---------
Total costs and expenses $ 57,009 $ 50,456 $ 163,765 $ 166,476
--------- --------- --------- ---------
(Loss) income before income taxes and
cumulative effect of change in
accounting principles $ (4,844) $ 8,796 $ 669 $ 106,846
Income tax (provision) benefit:
Current (257) 9,649 (344) (1,716)
Deferred 3,270 (12,675) 2,228 (37,686)
--------- --------- --------- ---------
(Loss) income before cumulative effect of
change in accounting principles (1,831) 5,770 2,553 67,444
--------- --------- --------- ---------
Cumulative effect of change in
accounting principles -- -- (18,103) 2,026
--------- --------- --------- ---------
Net (loss) income $ (1,831) $ 5,770 $ (15,550) $ 69,470
========= ========= ========= =========
Weighted average number of common
shares outstanding:
Basic 39,245 39,058 39,194 38,896
Diluted 39,245 40,079 40,449 40,262
Net income per common share before
cumulative effect of change in
accounting principles
Basic $ (0.05) $ 0.15 $ 0.06 $ 1.73
========= ========= ========= =========
Diluted $ (0.05) $ 0.14 $ 0.06 $ 1.68
========= ========= ========= =========
Net (loss) income per common share
Basic $ (0.05) $ 0.15 $ (0.40) $ 1.79
========= ========= ========= =========
Diluted $ (0.05) $ 0.14 $ (0.38) $ 1.73
========= ========= ========= =========
TOM BROWN, INC. AND SUBSIDIARIES
Supplemental Financial Information
Three and Nine Months ended September 30, 2002 and 2001
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- -------------------------
2002 2001 2002 2001
--------- --------- --------- ---------
(in thousands)
Discretionary Cash Flow (1):
Net (loss) income $ (1,831) $ 5,770 $ (15,550) $ 69,470
RECONCILING ITEMS:
Depreciation, depletion and amortization 22,823 17,973 68,846 52,674
Exploration costs 4,150 10,490 15,334 24,621
Impairments of leasehold costs 1,392 1,200 4,173 3,600
Deferred taxes (3,270) 12,675 (2,228) 37,686
Gain on sale of property -- -- (4,004) (10,078)
Current tax impact on gain on sale of property -- -- -- 3,527
Change in derivative fair value (299) 1,950 1,042 2,953
Loss on marketable security -- -- 600 --
Acceleration of stock options -- -- -- 3,747
Cumulative effect of change in
accounting principles -- -- 18,103 (2,026)
--------- --------- --------- ---------
Discretionary cash flow $ 22,965 $ 50,058 $ 86,316 $ 186,174
========= ========= ========= =========
Discretionary cash flow per common share
Basic $ 0.59 $ 1.28 $ 2.20 $ 4.79
========= ========= ========= =========
Diluted $ 0.59 $ 1.25 $ 2.13 $ 4.62
========= ========= ========= =========
(1) Discretionary cash flow is presented herein because of its wide acceptance
as a financial indicator of a company's ability to internally fund
exploration and development activities and to service or incur debt.
Discretionary cash flow should not be considered as an alternative to net
cash provided by operating activities, net income (loss) or income (loss)
from continuing operations, as defined by generally accepted accounting
principles. Discretionary cash flow should also not be considered as an
indicator of the Company's financial performance, as an alternative to cash
flow, as a measure of liquidity or as being comparable to other similarly
titled measures of other companies.
September 30, December 31,
BALANCE SHEET DATA: 2002 2001
------------------- ------------- -----------
Total assets $853,978 $844,975
Net working capital 7,382 11,278
Total debt 153,954 120,570
Stockholders' equity 557,922 575,228
Net debt/total book capital 21% 16%
TOM BROWN, INC. AND SUBSIDIARIES
Supplemental Operational Data (Unaudited)
Three and Nine Months ended September 30, 2002 and 2001
Three months ended Nine months ended
September 30, September 30,
------------------------ ------------------------
2002 2001 2002 2001
--------- --------- --------- ---------
Production (net of royalties)
Natural Gas (Bcf)
United States 16.4 14.1 49.6 41.0
Canada 1.5 1.7 4.9 5.1
--------- --------- --------- ---------
17.9 15.8 54.5 46.1
Oil (MBbls)
United States 130.7 174.0 482.6 535.8
Canada 56.3 36.6 159.8 120.9
--------- --------- --------- ---------
187.0 210.6 642.4 656.7
NGLs (MBbls)
United States 303.0 301.7 936.3 838.2
Canada 52.7 39.9 144.7 108.5
--------- --------- --------- ---------
355.7 341.6 1,081.0 946.7
Average daily production (net of royalties)
Natural Gas (Mmcf)
United States 177.6 153.8 181.9 150.0
Canada 16.8 18.4 17.8 19.0
--------- --------- --------- ---------
194.4 172.2 199.7 169.0
Oil (Bbls)
United States 1,420 1,892 1,768 1,963
Canada 612 397 585 442
--------- --------- --------- ---------
2,032 2,289 2,353 2,405
NGLs (Bbls)
United States 3,294 3,280 3,430 3,071
Canada 573 434 530 397
--------- --------- --------- ---------
3,867 3,714 3,960 3,468
Average realized price (including effects of hedges):
Natural Gas ($/Mcf)
United States $ 1.70 $ 2.63 $ 1.94 $ 4.36
Canada 2.46 2.76 2.68 3.81
Combined 1.77 2.64 2.01 4.30
Oil ($/Bbl)
United States $ 26.12 $ 24.40 $ 22.56 $ 24.99
Canada 25.90 23.89 23.50 27.60
Combined 26.05 24.30 22.85 25.47
NGLs ($/Bbl)
United States $ 10.73 $ 10.91 $ 9.74 $ 14.44
Canada 17.97 22.55 14.98 23.07
Combined 11.80 12.27 10.44 15.43