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EXHIBIT 99.2
NUEVO ENERGY COMPANY
2001 FORECAST
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
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YTD 2001
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REVENUES:
Oil revenues................................................................................................ $319,404
Gas revenues................................................................................................ 84,836
Liquids revenues............................................................................................ 3,482
Interest and other income (1)............................................................................... 685
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Total revenues........................................................................................... $408,408
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COSTS & EXPENSES:
Lease operating expenses.................................................................................... $197,585
Depreciation, depletion and amortization.................................................................... 73,526
Exploration costs........................................................................................... 23,298
General and administrative expenses......................................................................... 31,748
Interest expense............................................................................................ 41,474
TECONS - Dividends expense.................................................................................. 6,613
Other expense............................................................................................... 1,311
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Total expenses........................................................................................... $375,555
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Net earnings before taxes................................................................................... $ 32,853
Income Taxes (2):
Current.................................................................................................. 657
Deferred................................................................................................. 12,484
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Net income (loss)........................................................................................... $ 19,712
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Earnings per share
(diluted).................................................................................................. $ 1.15
Discretionary Cash Flow (3).............................................................................. $131,457
Discretionary Cash Flow per share (diluted).............................................................. $ 7.64
EBITDAX (4)................................................................................................. $177,764
Weighted average common and dilutive potential
common shares outstanding................................................................................ 17,208
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Prices:
Oil ($/BBL) - Consolidated............................................................................... $ 16.75
Oil ($/BBL) - reference price (NYMEX).................................................................... $ 27.30
Gas ($/MCF).............................................................................................. $ 5.93
Gas ($/MCF) - reference price (NYMEX).................................................................... $ 5.67
Production:
Oil (MBBL)............................................................................................... 19,073
BBLS/D................................................................................................... 52,255
Gas (MMCF)............................................................................................... 14,295
MMCF/D................................................................................................... 39
Liquids (MBBL)........................................................................................... 170
MBOE - including liquids.................................................................................... 21,625
Lease Operating Expense per BOE............................................................................. $ 9.14
General & Administrative Expense per BOE.................................................................... $ 1.47
Fixed Charge Coverage Ratio................................................................................. 3.7
Long-term Debt.............................................................................................. $418,424
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Notes:
(1) As a matter of policy, we will not provide guidance on other income, other
expense, or gain or loss on sales of assets, except as specifically noted.
(2) Assumes an effective tax rate of 40%; 5% current, 95% deferred.
(3) Calculated as Net Income, plus Deferred Taxes, plus Exploration Costs, plus
DD&A, less Gain on Sale of Assets plus Loss on Sale of Assets. Actual
amounts may include additional cash flow adjustments not specified above,
resulting in immaterial differences.
(4) Calculated as Net Earnings before Taxes, plus Exploration Costs, plus DD&A,
less Gain on Sale of Assets plus Loss on Sale of Assets. Actual amounts may
include additional cash flow adjustments not specified above, resulting in
immaterial differences.
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2001 FINANCIAL GUIDANCE
The estimates listed below contain assumptions which we believe are reasonable.
We caution that these estimates are based on currently available information as
of the date hereof. We are not undertaking any obligation to update these
estimates as conditions change or as additional information becomes available.
All of the estimates and assumptions set forth in this document constitute
forward-looking statements within the meaning of Section 27A of the Securities
Act of 1933, Section 21E of the Securities Exchange Act of 1934 and the Private
Securities Litigation Reform Act of 1995. Although we believe that these
forward-looking statements are based on reasonable assumptions, we can give no
assurance that our expectations will in fact occur and caution that actual
results may differ materially from those in the forward-looking statements. A
number of factors could affect our future results or the energy industry
generally and could cause our expected results to differ materially from those
expressed in this release. These factors include, among other things:
- Increases or decreases in oil and gas prices;
- Compliance with environmental regulations and other governmental laws
and regulations applicable to the oil and gas industry;
- Unanticipated problems or successes encountered during the exploration
for and exploitation and production of oil and gas;
- Political and economic events and conditions in the foreign
jurisdictions in which we operate;
- Our hedging activities;
- Decisions we make regarding our debt and equity structure, including the
decision to issue additional capital stock or debt securities;
- Our ability to deliver oil and gas to commercial markets;
- Changes in consumer demand;
- The impact of competition;
- The uncertainty of estimates of oil and gas reserves and production
rates;
- The impact of the adoption of SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities";
- The risk factors and other conditions described in the report on
Form 10-K for the period ended December 31, 1999 and in the reports on
Form 10-Q for the periods ended March 31, 2000, June 30, 2000 and
September 30, 2000.
These estimates do not include the forecasted impact of SFAS No. 133 which the
Company must adopt by January 1, 2001. These estimates will be updated for the
incorporation of SFAS No. 133 in February 2001. On adoption of SFAS No. 133, the
provisions of this statement must be applied prospectively. The Company has
completed an inventory of all known derivatives and is in the process of
documenting the relevant hedge relationships. The Company expects that the
adoption of SFAS No. 133 will primarily increase the volatility of other
comprehensive income
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and results of operations. In general, the amount of volatility will vary with
the level of derivative activities during any period.
These estimates also assume that we will not engage in any material transactions
such as acquisitions or divestitures of assets, formation of joint ventures or
sale of debt or equity securities. We continually review these types of
transactions as part of our corporate strategy, and may engage in any of them
without prior notice.
CRUDE OIL PRODUCTION
We anticipate that our 2001 production will be between 19.0 and 19.2 million
barrels (52,055 - 52,603 barrels per day) which incorporates downtime for
potential electrical interruptions, pump repairs as well as planned downtime for
scheduled field maintenance. Of this 2001 volume, approximately 88% will be
derived from California, 11% from the Republic of Congo and 1% from other U.S.
However, weather, unexpected subsurface conditions, power supply disruptions and
other unforeseen operating hazards may have an adverse impact on Nuevo's
production volumes and better than expected development drilling results or
exploration success could have a positive effect.
CRUDE OIL PRICES
Realized crude oil prices for 2001 are expected to be between $16.00 and $17.50
Bbl. Realized prices are based on the current NYMEX WTI futures price and are
adjusted for the California crude oil sales contract, the impact of hedges, and
the price sharing agreements for our Point Pedernales and Congo production.
. Nuevo realizes approximately 70% of the NYMEX WTI price for California crude
oil production, before hedges. About half of Nuevo's California crude oil
production is considered heavy oil (15 (degrees) API quality crude oil or
heavier produced by thermal operations). The market price for California
heavy crude oil differs from the established market indices for oil elsewhere
in the U.S., due principally to the higher transportation and refining costs
associated with heavy oil.
. Nuevo realizes approximately 95% of the NYMEX WTI price for East Texas crude
oil production, before hedges.
. Nuevo realizes approximately 80% of the NYMEX WTI price for Congo crude oil
production, before hedges. Nuevo's Congo production is a relatively heavy
crude oil (16 (degrees) - 20 (degrees) API gravity) which is processed into
low-sulfur, No. 6 fuel oil for sale to worldwide markets. The market for
residual fuel oil differs from the markets for WTI and other benchmark crudes
due to its primary use as an industrial or utility fuel versus the higher
value transportation fuel component, which is produced from refining most
grades of crude oil.
The price of crude oil is subject to large fluctuations in response to
relatively minor changes in the supply of and demand for crude oil, market
uncertainty and a variety of additional factors beyond Nuevo's control. Any
substantial or extended decline in the price of crude oil would have an adverse
effect on Nuevo.
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PRICE RISK MANAGEMENT POLICY
Nuevo's price risk management policy was designed to accomplish the following
objectives: 1) to ensure sufficient capital for reserve replacement and 2) to
ensure fixed charge coverage ratios are maintained. NO ADDITIONAL CONTRACTS HAVE
BEEN ADDED TO THE CRUDE OIL HEDGE SCHEDULE LISTED BELOW SUBSEQUENT TO THE
INITIAL WEBSITE POSTING ON NOVEMBER 14, 2000.
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CRUDE OIL HEDGES
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SWAPS Volume WTI Price
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1Q01 26,000 B/D $19.52 Bbl.
2Q01 25,000 B/D $19.54 Bbl.
3Q01 20,000 B/D $21.22 Bbl.
4Q01 15,500 B/D $22.95 Bbl.
1Q02 12,500 B/D $25.91 Bbl.
FLOORS Volume WTI Price
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2Q02 19,000 B/D $22.00 Bbl.
3Q02 14,000 B/D $22.00 Bbl.
4Q02 14,000 B/D $22.00 Bbl.
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For a swap transaction, we receive a fixed price for our production and pay the
counter party a floating price based on a market index. For a floor (purchased
put), we receive the floor price if the floating price falls below the floor
price. Swaps fix the price we receive for production, while floors establish a
minimum price.
NATURAL GAS PRODUCTION
We anticipate that our 2001 production will be between 14.1 and 14.4 Bcf (38.6
MMcfd - 39.5 MMcfd). Of this volume, approximately 90% will be derived from
California and 10% from other U.S. However, weather, unexpected subsurface
conditions, and other unforeseen operating hazards may have an adverse impact on
our production volumes and better than expected development drilling results or
exploration success could have a positive effect.
NATURAL GAS PRICES
Realized gas prices for 2001 are expected to be between $5.60 and $6.25 Mcf
based on the current NYMEX strip price. Realized gas prices generally average
within +/- $0.10 Mcf of the NYMEX strip price; however, the price differential
can vary by a significantly greater amount at different points in time.
The price of natural gas is subject to large fluctuations in response to
relatively minor changes in the supply of and demand for natural gas, market
uncertainty and a variety of additional factors beyond Nuevo's control. Natural
gas prices have been high recently, especially in the California market. No
assurances can be made that they will remain at current levels.
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CALIFORNIA NATURAL GAS MARKET VOLATILITY
Nuevo continues to work to optimize the use of its gas reserves in a very
volatile California gas market. The Company projects that for all of 2001 it
will produce more natural gas than it will consume. Given that fact, the Company
believes that any decisions to reduce gas consumption for steam usage which
would reduce near-term crude oil production, will have a net positive impact on
overall earnings, cash flow and EVA versus this forecast. In California, Nuevo
currently produces approximately 39 MMcfd and consumes approximately 32 MMcfd in
steaming operations. Beginning mid-December 2000, a portion of currently
consumed natural gas may be sold into the California market to capture
temporarily high spot gas prices. Beyond December 2000, Nuevo will continue to
look for opportunities to take advantage of its net long natural gas position in
California. The impact of any such action is not reflected in these estimates
but would have a net positive effect. Finally, Nuevo expects to continue to add
to gas reserves and production in California through both exploration and
exploitation efforts in 2001.
NATURAL GAS HEDGES
Nuevo does not have any of its natural gas production hedged.
LIQUIDS
We anticipate that our 2001 production will be between 167,000 and 173,000
barrels (458 and 474 barrels per day). Historically, the estimated realized
price for liquids is approximately 80% of the NYMEX WTI price. The same factors
that affect our oil and gas production and pricing can also have an effect on
the production and pricing of liquids.
2001 Total Production
We anticipate that our 2001 production will be between 21.5 and 21.8 million BOE
for the year with 88% crude oil. However, our production volumes are subject to
curtailments, delays, and cancellations as a result of a lack of capital or
other problems such as, weather, compliance with governmental regulations or
price controls, electrical shortages, mechanical difficulties or shortages or
delays in the delivery of equipment. Changes to the capital budget (i.e. dollar
amount and projects) and exploratory drilling success will also have an impact
on production volumes.
LEASE OPERATING EXPENSE (INCLUDES PRODUCTION AND AD VALOREM TAXES)
Nuevo uses natural gas to generate steam for its thermal production. Since
recent natural gas prices have increased significantly, gas costs have become a
major component of LOE. With more normalized natural gas prices in 1999, steam
costs contributed less than $1.00 BOE to LOE. During 2000, steam costs have
averaged over $1.80 BOE through September 30, 2000. Due to higher gas costs, we
expect 2001 LOE to be between $8.90 and $9.35 BOE. Note that company-wide Nuevo
currently produces 28% more natural gas in total than we consume in our thermal
operations, so the net effect of higher natural gas prices on our income
statement is positive.
DEPRECIATION, DEPLETION AND AMORTIZATION
We anticipate that the DD&A rate for 2001 will be between $3.35 and $3.50 BOE.
Our DD&A rate is based on an estimate of our proved reserves for the most recent
period.
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EXPLORATION EXPENSES
We caution that this is an inherently difficult expense category to estimate and
that this estimate can be volatile due to the number of wells drilled, completed
and the success rate in any given quarter and any potential changes to the
capital budget. Exploration expenses for 2001 should be between $22.5 million
and $24.0 million. In California, the Rainbow well will be testing at the end
of the fourth quarter 2000. This well has a dry hole cost of $1.6 million
which, if dry, will be expensed either in the fourth quarter 2000 or the first
quarter 2001, depending on the timing of well results.
GENERAL AND ADMINISTRATIVE EXPENSE
We anticipate that the G&A rate for 2001 will be between $1.40 and $1.55 BOE.
The factor that could have the greatest impact on G&A is the mark to market
accounting for Nuevo's deferred compensation plan which is based on the price of
Nuevo common stock. As a matter of policy, Nuevo accrues target EVA bonuses on
a quarterly basis which may not represent actual results at year-end.
INTEREST EXPENSE
We anticipate that our interest expense for 2001 will be between $41 million
and $42 million.
TERM CONVERTIBLE SECURITIES (TECONS) - DIVIDEND EXPENSE
We expect our annual TECONS dividend expense to be $6.6 million ($1.65 million
per quarter).
INCOME TAXES
We expect our effective income tax rate to be 40% (inclusive of applicable
federal and state taxes) in 2001 and our deferred tax ratio to be 95%.
WEIGHTED AVERAGE COMMON AND DILUTIVE POTENTIAL COMMON SHARES OUTSTANDING
Nuevo repurchases its common shares under a Board authorized share repurchase
program. As of September 30, 2000, approximately 956,000 shares remained
authorized for repurchase at management's discretion under the most recent
authorization. While the company's policy is not to comment on the status of the
share repurchase program until the authorization is exhausted or when quarterly
financial statements are published, the weighted average shares shown for these
forecast periods are updated for material changes in share balances through the
forecast date. No future anticipated share repurchases are included in the
forecast
CAPITAL EXPENDITURES
We expect base capital expenditures for 2001 to be approximately $181 million.
Depending on the level of drilling success, capital expenditures could be
increased by approximately $24 million to $205 million. Some of the factors
impacting the level of capital expenditures include crude oil and natural gas
prices as well as the volatility in these prices, the cost and availability of
oilfield services, exploratory drilling success, acquisitions and divestitures
and the level and availability of external financing.
