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EXHIBIT 99.1
NUEVO ENERGY COMPANY
2001 FORECAST - WEB
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
ACTUAL FORECAST
-------------- --------------------------------------------
3 MONTHS ENDED 3 MONTHS ENDED 6 MONTHS ENDED
MARCH 31, 2001 JUNE 30, 2001 DEC. 31, 2001 2001
-------------- -------------- -------------- ---------
REVENUES:
Oil revenues ........................................ $ 67,184 $ 64,369 $ 139,854 $ 271,407
Gas revenues ........................................ 50,723 33,899 34,372 118,994
Liquids revenues .................................... 1,324 1,213 1,558 4,095
Interest and other income (1) ....................... 698 224 154 1,075
============== ============== ============== =========
Total revenues ................................. $ 119,929 $ 99,705 $ 175,938 $ 395,573
============== ============== ============== =========
COSTS & EXPENSES:
Lease operating expenses ............................ $ 59,157 $ 48,054 $ 83,513 $ 190,724
Depreciation, depletion and amortization ............ 19,835 19,993 40,398 80,226
Exploration costs ................................... 2,665 3,106 19,718 25,489
General and administrative expenses(2) .............. 7,276 10,794 15,377 33,447
Interest expense .................................... 11,135 10,786 22,273 44,195
TECONS - Dividends expense .......................... 1,653 1,653 3,306 6,612
Other expense (1) ................................... 2,122 1,985 589 4,695
============== ============== ============== =========
Total expenses ................................. $ 103,843 $ 96,370 $ 185,174 $ 385,388
============== ============== ============== =========
Net earnings before
taxes ............................................... $ 16,086 $ 3,334 $ (9,236) $ 10,185
Income Taxes:
Current ........................................ 560 171 (462) 269
Deferred ....................................... 5,923 1,189 (3,233) 3,879
============== ============== ============== =========
Net Income (loss) ................................... $ 9,603 $ 1,975 $ (5,542) $ 6,036
============== ============== ============== =========
Earnings per share (diluted) ........................ $ 0.57 $ 0.12 $ (0.33) $ 0.36
Discretionary Cash Flow (3) .................... $ 39,532 $ 28,636 $ 52,620 $ 120,789
Discretionary Cash Flow per share (diluted) .... $ 2.33 $ 1.68 $ 3.10 $ 7.10
EBITDAX (4) ......................................... $ 51,703 $ 39,565 $ 76,460 $ 167,035
Weighted average common and dilutive potential
common shares outstanding ...................... 17,003 17,008 16,997 17,001
Prices:
Oil ($/BBL) - Including hedges ................. $ 16.21 $ 15.16 $ 16.90 $ 16.29
Oil ($/BBL) - reference price (NYMEX) .......... $ 28.73 $ 27.96 $ 25.14 $ 26.74
Gas ($/MCF) .................................... $ 13.26 $ 11.73 $ 5.09 $ 8.84
Gas ($/MCF) - reference price (NYMEX) .......... $ 7.27 $ 4.78 $ 3.38 $ 4.70
Production:
Oil (MBBL) ..................................... 4,144 4,246 8,276 16,666
BBLS/D ......................................... 46,045 46,656 44,976 45,660
Gas (MMCF) ..................................... 3,824 2,891 6,749 13,464
MMCF/D ......................................... 43 32 37 37
Liquids (MBBL) ................................. 44 42 83 168
MBOE - Including liquids ............................ 4,825 4,765 9,483 19,078
Lease Operating Expense per BOE ..................... $ 12.26 $ 10.08 $ 8.81 $ 10.00
General & Administrative Expense per BOE ............ $ 1.51 $ 2.27 $ 1.62 $ 1.75
Fixed Charge Coverage Ratio ......................... 4.0 3.2 3.0 3.3
Long-term Debt ...................................... $ 409,702 $ 409,702 $ 459,253 $ 459,253
NOTES:
(1) As a matter of policy, we will not provide guidance on other income, other
expense, gain or loss on sales of assets, or gain or loss on derivatives,
except as specifically noted.
(2) In the 2Q01, G&A includes severance costs associated with the resignation
of Nuevo's CEO.
(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
Dividends on TECONS, plus Interest Expense, 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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SECOND QUARTER 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 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 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 year ended December 31, 2000, and in the report on Form
10-Q for the quarter ended March 31, 2001.
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.
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CRUDE OIL PRODUCTION
We anticipate that our second quarter 2001 production will be between 4.1 and
4.4 million barrels (45,055 - 48,352 barrels per day) which incorporates a
reduction in crude oil volume due to a decrease in steaming, and downtime for
potential electrical interruptions, pump repairs, scheduled field maintenance
and replacement of the carbon dioxide unit at the Rincon Onshore Separation
Facility (ROSF). Of this second quarter 2001 volume, approximately 86% will be
derived from California, 13% 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 the second quarter 2001 are expected to be between
$15.00 and $15.30 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.
o Nuevo realizes approximately 72% 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 degree 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.
o Nuevo realizes approximately 95% of the NYMEX WTI price for East Texas
crude oil production, before hedges.
o 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 - 20 degree 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.
CRUDE OIL HEDGES
SWAPS VOLUME WTI PRICE
- ----- ------ ----------
2Q01 26,200 B/D $19.84 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
- ------ ------ ---------
2Q02 19,000 B/D $22.00 Bbl.
3Q02 14,000 B/D $22.00 Bbl.
4Q02 14,000 B/D $22.00 Bbl.
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 second quarter 2001 production will be between 2.6 and
3.1 Bcf (28.6 MMcfd - 34.1 MMcfd) which incorporates a reduction in natural gas
volume due to a delay in the mobilization of a drilling rig offshore California
and downtime associated with the replacement of the carbon dioxide unit at the
Rincon Onshore Separation Facility (ROSF). Of this second quarter 2001 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 the second quarter 2001 are expected to be between
$11.50 and $12.00 Mcf based on our assumption regarding the California price
differential versus the current NYMEX strip price. In 2001, natural gas prices
in California have greatly exceeded NYMEX prices, and a meaningful basis
differential is expected to persist through much of 2001.
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 it will produce more
natural gas than it will consume in 2001. 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. Beginning in mid-December 2000, Nuevo reduced its
gas consumption related to cyclic steaming operations for higher steam-oil ratio
(SOR) wells in order to capture robust California spot gas prices. This forecast
assumes a further reduction in gas consumption for steaming operations in 2001
versus 2000. Nuevo will continue to look for opportunities to take advantage of
its net long natural gas position in California. 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 second quarter 2001 production will be between 41,000 and
43,000 barrels (451 and 473 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.
SECOND QUARTER 2001 TOTAL PRODUCTION
We anticipate that our second quarter 2001 production will be between 4.6 and
4.9 million BOE with 89% 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.
2001 TOTAL PRODUCTION
We anticipate that total production for 2001 will be between 18.9 and 19.3
MMBOE. This estimate incorporates Nuevo's preliminary assessment of the duration
of the production shut-in resulting from the failure of a carbon dioxide
treatment vessel at the Rincon Onshore Separation Facility (ROSF) located in
Ventura County, California.
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 averaged
$2.30 BOE. Incorporating the impact of high gas costs and a reduction in steam
usage, we expect the second quarter 2001 LOE to be between $9.90 and $10.20 BOE.
The projected reduction in steam usage is currently expected to continue
throughout 2001. Note that company-wide Nuevo produces 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. In California, Nuevo produced 40
MMcfd and consumed 22 MMcfd in thermal operations in the first quarter 2001.
DEPRECIATION, DEPLETION AND AMORTIZATION
We anticipate that the DD&A rate for the second quarter 2001 will be between
$4.10 and $4.30 BOE. Our DD&A rate has been revised upward based on SEC proved
reserves at December 31, 2000.
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EXPLORATION COSTS
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 the second quarter 2001 should be
between $2.5 million and $3.7 million.
GENERAL AND ADMINISTRATIVE EXPENSE
We anticipate that the G&A rate for the second quarter 2001 will be between
$2.15 and $2.35 BOE. The G&A expense for the 2Q01 includes severance costs
associated with the resignation of Nuevo's CEO. 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 the second quarter 2001 will be
between $10.0 million and $11.5 million.
TERM CONVERTIBLE SECURITIES (TECONS) - DIVIDEND EXPENSE
We expect our second quarter 2001 TECONS dividend expense to be $1.65 million.
INCOME TAXES
We expect our effective income tax rate for the second quarter 2001 to be 41%
(inclusive of applicable federal and state taxes) and our deferred tax ratio to
be 87%.
WEIGHTED AVERAGE COMMON AND DILUTIVE POTENTIAL COMMON SHARES OUTSTANDING
Nuevo repurchases its common shares under a Board authorized share repurchase
program. As of March 31, 2001, approximately 7,700 shares remained authorized
for repurchase at management's discretion under the existing authorization. On
February 12, 2001, the Board authorized the repurchase of an additional 1
million shares of Nuevo common stock. 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 which includes share repurchases and
options in the money. No future anticipated share repurchases are included in
the forecast.
CAPITAL EXPENDITURES
We expect base capital expenditures for 2001 to be approximately $160 million,
assuming gas prices remain at robust levels for the remainder of the year.
Depending on the level of drilling success this year, capital expenditures could
be increased by approximately $18 million in 2001. 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.
SFAS NO. 133
Nuevo expects that SFAS No. 133 will primarily increase the volatility of other
comprehensive income and results of operations. In general, the amount of
volatility will vary with the level of derivative activities during any period.
Nuevo will not provide guidance on this item.