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Exhibit 99.1
2000 Fourth Quarter and 2001 Financial Model Estimates
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Updated November 15, 2000
This document is intended to provide information and estimates to prepare
financial models of the Barrett Resources Corporation's ("Barrett" or the
"Company") expected activities. The information included in this document
contains forward-looking statements within the meaning of Section 21E of the
Securities Exchange Act of 1934. Barrett believes that its expectations are
based on reasonable assumptions. No assurances, however, can be given that its
goals will be achieved. Actual results may differ materially due to risk and
uncertainties, including but not limited to, drilling results, industry
conditions, and the price of gas and oil. For additional information concerning
important factors that may cause actual results to differ materially from those
projected, see the Company's Form 10-K for the year ended December 31, 1999 and
the "Risk Factor" section of the reoffer prospectus included in the Company's
Registration Statement on Form S-8 filed with the Securities and Exchange
Commission ("SEC") on May 9, 2000.
This document will be maintained on Barrett's web site and was included in
a Form 8-K filed with the SEC on November 15, 2000. Although the Company is not
undertaking any duty or requirement to update the information contained in this
report, if the Company decides to provide to any third party updated information
that the Company believes may be material, the Company first will include that
information in a Form 8-K filed with the SEC. That information will then be
posted on Barrett's web site. Revisions that may be material are expected to
include the addition of information for a new financial reporting period or
changes of five percent or more in the Company's production quantities, earnings
or cash flow estimates, exclusive of commodity price changes. This document does
not include, and any updates that the Company may provide are not expected to
include, management forecasts of commodity sales price or basis differentials
between various delivery points for natural gas. Minor revisions or updates to
this information that the Company does not believe are material will be made
directly to the document maintained on the web site without announcement. Minor
revisions and updates are expected to address requests for additional detail
supporting information included in this report that do not have a material
effect on the financial estimates. Examples may include production by basin or
wells drilled in a particular area. Minor updates may also include incorporating
information obtained from monthly financial reports to prepare more accurate
quarterly estimates. Minor information updates currently are not to be expected
to affect production, earnings or cash flow estimates by more than five percent
on a cumulative basis from the last report furnished on a Form 8-K. In any
event, the Company expects to file a Form 8-K to update this report on a
quarterly basis following filing of the appropriate Form 10-Q or 10-K being
filed with the SEC, although the Company is not undertaking any duty or
requirement to provide any such updates.
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Analysis of certain operating results for the quarter ended September 30, 2000
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The information contained in this document regarding results of operations
for the quarter ended September 30, 2000 complements the financial statements
and Management's Discussion and Analysis of Financial Condition and Results of
Operations included in the Form 10-Q filed on November 13, 2000 and the comments
reported on the earnings conference call held on November 2, 2000. A transcript
of the earnings conference call is available at the Company's web site located
at www.brr.com.
Oil and gas production and capital expenditures
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The following table reports capital expenditures, production quantities and
direct lifting costs by basin for the quarter ended September 30, 2000:
<TABLE>
<CAPTION>
Production Quantities
Net ----------------------------- Direct
Basin CAPEX Oil Gas LOE
------------------------- ----------- ----------- ----------- -----------
(000's) (Mbo) (Mmcf) (000's)
<S> <C> <C> <C> <C>
Rocky Mountains
Piceance $ 25,776 8 9,421 $ 781
Wind River 10,392 15 4,552 726
Powder River - CBM 12,491 - 6,660 2,051
Other 5,187 171 1,257 1,371
Mid-Continent 2,065 5 3,995 1,411
Gulf of Mexico 1,804 18 1,369 801
Other 95 - - -
----------- ----------- ----------- -----------
Total $ 57,810 217 27,253 $ 7,142
=========== =========== =========== ===========
</TABLE>
Oil and gas production revenue
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Gas production revenue for the quarter is net of $12.6 million for payments
under the Company's long-term hedges. Gas production revenue has been reduced
by $4.6 million for pipeline transportation costs to move gas from the Rocky
Mountains to sales points in the mid-continent region of United States.
Other income
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Other income includes gas gathering revenue of $1.9 million, primarily from
the Company's gas gathering system located in the Piceance Basin.
Interest expense
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Interest expense of $1.2 million was capitalized as property and equipment
costs.
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Estimation parameters
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The following fourth quarter 2000 and full-year 2001 estimates have been
prepared based upon current expectations for gas production, natural gas prices
(including current hedged positions), tax rates, expenses and cash flow, and
other assumptions.
Financial estimates are being provided for a single point in a range that
the Company currently believes could be up to ten percent more or less than the
specific estimate provided in this document. Excluding consideration of the
Company's sensitivity to volatile commodity prices, management expects that
financial forecasts of future cash flow and earnings computed using these
estimates will be within five percent of the actual amounts.
Estimates of certain operating results for the quarter ending December 31, 2000
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Capital expenditures
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Capital expenditures for the fourth quarter are estimated at $100 million,
including $55 million for the acquisition and development of gas properties
located in the Raton Basin in southern Colorado.
Oil and gas production
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The Company estimates fourth quarter gas production will be approximately
28 bcf, and oil production will be approximately 215,000 barrels.
Gas sales commitments and transportation
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The Company has entered into certain fixed price swaps for 71,000 mmbtu of
gas per day to be delivered to Rocky Mountain sales points for a five-year term
ending February 2003 at an average Rocky Mountain sales price of approximately
$1.73 per mmbtu. These hedge positions are associated with Rocky Mountain
production and are referred to as "long-term hedges". Any gain or loss from
these positions is recorded as an adjustment to oil and gas production revenue.
For the quarter ended December 31, 2000, the Company is committed to sell
approximately six bcf of gas production subject to these long-term hedges.
During the quarter the Company expects to sell approximately two bcf of gas
under terms of fixed price contracts at a Rocky Mountain price of $2.30 per
mmbtu.
The Company holds firm transportation commitments for an average of
approximately 230,000 mmbtu of gas per day from the Rockies to sales points in
the Mid-Continent region of the United States at an average tariff of 22 cents
per mmbtu. This transportation capacity exceeds the Company's current gas
production available to be transported from the Rockies.
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Transportation costs and benefits associated with producing activities are
recorded as an adjustment to gas sales revenue. Any gain or loss on
transportation used to sell third party gas will be recorded in gas trading
activities included in other income and expense.
Oil and gas production costs
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Lease operating expenses are expected to average 20 cents per mcfe for the
fourth quarter. Gathering, compression and processing costs are expected to
average 20 cents per mcfe for the fourth quarter. Production taxes are expected
to average between 8.5 and 9.0 percent of wellhead sales value.
Depreciation, depletion and amortization
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Full cost depletion and amortization was provided at a rate of
approximately 80 cents per mcfe in the third quarter with a total depletion,
depreciation and amortization rate of 84 cents per mcfe for the quarter.
Management does not yet have information to revise these estimates for the
fourth quarter. Any revision due to the year-end review of reserves and
unevaluated costs excluded from the full cost amount of oil and gas properties
will be recorded in the fourth quarter.
General and administrative expense
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Management expects fourth quarter general and administrative expense to be
comparable to third quarter expense of approximately 22 cents per mcfe.
Gas trading
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Excluding mark to market gains or losses, the Company expects its gas
trading operation to earn approximately $1 million for the fourth quarter from
its remaining gas sales commitments, sales of gas from storage and utilization
of excess transportation capacity.
As of September 30, 2000, the Company recorded an allowance of $31.4
million to mark to market gas sales commitments and trading positions. These
positions were entered into prior to June 30, 2000 and do not qualify for
deferral under hedge accounting treatment. Of the net allowance, $8.3 million
relates to commitments and trading positions that will settle in the fourth
quarter of 2000. If the settlement prices are unchanged from the prices in
effect at September 30, the Company expects the commitments would be settled at
the losses estimated at the end of the third quarter with no further gain or
loss to the Company. Price fluctuations from the prices used at the end of the
third quarter could result in an additional gain or loss compared to the
allowances recorded at September 30.
As of December 31, 2000, the Company will be obligated under the remaining
gas trading positions that had a mark to market value of $23.1 million based on
futures prices
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in effect as of September 30, 2000. These positions include approximately 40 bcf
of gas sold under sales commitments that do not qualify for deferral under hedge
accounting. The value of these positions at December 31 will not be determined
until future sales prices are established at the end of the quarter. Depending
on price fluctuations from September 30, the Company may record a non-cash gain
or loss on the remaining open positions as of December 31.
Provision for income taxes
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The provision for income taxes is expected to be approximately 38 percent
of income before income taxes. Cash income taxes are expected to be
approximately four percent with the remaining liability being recorded on the
balance sheet as deferred income taxes. The Company intends to prepare a
comprehensive study of its income tax liability as of December 31 and adjust the
cash and deferred components of the provision for income taxes as warranted.
Estimates of certain operating results for the year ending December 31, 2001
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The financial estimates for 2001 assume the Company's Board of Directors
will approve the 2001 capital expenditure budget to be submitted by management
on November 16, 2000.
Capital expenditures
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Capital expenditures for the year are estimated to be in a range of $200
million, subject to approval by the Board of Directors.
Oil and gas production
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The Company estimates 2001 gas production will be approximately 124 bcf, an
increase of approximately ten percent from 2000, and oil production will be
approximately 934,000 barrels, a four percent increase from 2000. This estimated
gas production may be revised pending the outcome of a hearing on the issuance
of water discharge permits for the Powder River Basin coal bed methane wells.
The Company may reallocate a portion of its capital expenditure budget from the
Powder River Basin to development activities in other areas if the water
discharge permits are delayed as a result of the hearing.
Gas sales commitments and transportation
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The Company has entered into certain fixed price swaps for 71,000 mmbtu of
gas per day to be delivered to Rocky Mountain sales points for a five-year term
ending February 2003 at an average Rocky Mountain sales price of $1.73 per
mmbtu. These hedge positions are associated with Rocky Mountain production and
are referred to as "long-term hedges". Any gain or loss from these positions is
recorded as an adjustment to production revenue.
During the year, the Company estimates it will sell approximately seven bcf
of gas under terms of fixed price contracts at a Rocky Mountain sales price of
$2.30 per mmbtu.
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For 2001, the Company holds firm transportation commitments for an average
of approximately 230,000 mmbtu of gas per day from the Rockies to sales points
in the mid-continent region of the United States at an average tariff of 22
cents per mmbtu. The Company's marketing personnel uses its transportation
capacity for both gas production and the purchase and resale of natural gas.
Transportation costs and benefits associated with producing activities are
recorded as an adjustment to gas sales revenue. Any gain or loss on
transportation used to sell third party gas will be recorded in gas trading
activities included in other income and expense.
Oil and gas production costs
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Lease operating expenses are expected to average 22 cents per mcfe for
2001. Gathering, compression and processing costs are expected to average 22
cents per mcf. Production taxes are expected to average between 9.0 and 9.5
percent of wellhead sales value.
Depreciation, depletion and amortization
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Full cost depletion and amortization is expected at a rate of approximately
80 cents per mcfe for 2001. Management may revise these estimates following
preparation of the December 31, 2000 reserve report and the annual review of
unevaluated costs excluded from the full cost amount of oil and gas properties.
Other depletion, depreciation and amortization is estimated at a rate of four
cents per mcfe for the year.
General and administrative expense
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Management expects 2001 general and administrative expense to be
approximately 22 cents per mmcfe.
Gas trading
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Excluding mark to market gains or losses, the Company expects to record a
gas trading gain of approximately $3 million for 2001.
Based on September 30, 2000 future gas prices, the mark to market allowance
for the Company's non-hedge gas sales positions to be settled in 2001 was $5.0
million. The realized gain or loss will be determined based on gas prices in
effect at settlement and the amounts may differ from the allowance recorded at
September 30, 2000.
As of December 31, 2001 the Company will be obligated under gas trading
positions that had a mark to market value of $18.1 million based on future
prices in effect as of September 30, 2000. The value of these positions at
December 31, 2001 will not be determined until future gas prices are established
at that date. These positions will be subject to non-cash mark to market gains
or losses throughout 2001.
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Provision for income taxes
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The provision for income taxes is expected to be approximately 38 percent
of income before income taxes. Cash income taxes are expected to be
approximately five percent with the remaining liability being recorded on the
balance sheet as deferred income taxes.
Other Matters
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Line of Credit
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The Company is currently negotiating a new $350 million five year Revolving
Line of Credit to replace its existing $250 million Revolving Line of Credit
that matures on September 30, 2002. The Company expects to enter into the new
line of credit in December 2000. Based on the Company's current debt rating, the
proposed terms provide that, at its election, the Company will pay interest at a
rate of LIBOR plus 1.25 percent or the Bank's prime rate. The proposed Credit
Agreement also provides for a commitment fee of .375 percent per annum on the
unused balance. Offering costs of approximately $2 million will be amortized
over the five-year life of the credit facility. As of September 30, 2000, the
outstanding balance under its existing line of credit was $175 million.
Subsequent to September 30, 2000, the Company borrowed additional funds to
consummate its $52.9 million acquisition of certain gas properties in the Raton
Basin located in southern Colorado.
Reserve Additions
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Barrett has not yet completed its year-end reserve report as of December
31, 2000 and therefore is unable to accurately estimate reserve replacement,
finding costs and full cost depletion and amortization. However, preliminary
December 31, 2000 reserves are currently estimated to be 1.3 Tcfe. Reserves as
of December 31, 2000 will be released in the latter half of January 2001.
