EXHIBIT 99.1
NUEVO ENERGY COMPANY
2001 FORECAST - WEB
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
RESTATED |
ACTUAL ACTUAL | FORECAST
-------------- -------------- | --------------------------------------
3 MONTHS ENDED 3 MONTHS ENDED | 3 MONTHS ENDED 3 MONTHS ENDED
MARCH 31, 2001 JUNE 30, 2001 | SEPTEMBER 30, 2001 DECEMBER 31, 2001 2001
-------------- ------------- | ------------------ ----------------- ---------
REVENUES: |
|
Oil revenues ................................ $ 65,106 $ 65,153 | $ 68,754 $ 64,794 $ 263,806
Gas revenues ................................ 50,723 33,908 | 10,579 8,797 104,007
Liquids revenues ............................ 1,324 1,199 | 929 686 4,138
Gain on sales of assets ..................... (336) 198 | -- -- (138)
Interest and other income (1) ............... 705 241 | 184 77 1,207
------------------------------|--------------------------------------------------
Total revenues ......................... $ 117,522 $ 100,699 | $ 80,446 $ 74,353 $ 373,021
------------------------------|--------------------------------------------------
COSTS & EXPENSES: |
|
Lease operating expenses .................... $ 57,287 $ 49,038 | $ 40,072 $ 37,253 $ 183,649
Depreciation, depletion and amortization .... 19,627 20,398 | 17,370 16,492 73,887
Exploration costs ........................... 2,665 5,382 | 5,340 5,264 18,651
General and administrative expenses (2) ..... 7,276 9,229 | 8,313 7,796 32,614
Interest expense ............................ 11,135 10,449 | 10,646 10,857 43,087
TECONS - Dividends expense .................. 1,653 1,653 | 1,653 1,653 6,612
Other expense (1) ........................... 1,793 99 | 570 267 2,729
------------------------------|--------------------------------------------------
Total expenses ......................... $ 101,436 $ 96,248 | $ 83,964 $ 79,582 $ 361,230
------------------------------|--------------------------------------------------
|
Net earnings before taxes ................... $ 16,086 $ 4,451 | ($ 3,518) ($ 5,229) $ 11,791
|
Income Taxes: |
Current ................................ 560 (460) | (67) (261) (229)
Deferred ............................... 5,923 2,252 | (1,340) (1,830) 5,005
------------------------------|--------------------------------------------------
Net Income (loss) ........................... $ 9,603 $ 2,659 | ($ 2,111) ($ 3,137) $ 7,014
-------------------------------------------------==================================================================================
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Earnings per share (diluted) ................ $ 0.56 $ 0.14 | ($ 0.12) ($ 0.18) $ 0.41
|
Discretionary Cash Flow (3) ................. $ 41,503 $ 29,540 | $ 19,904 $ 17,428 $ 108,375
Discretionary Cash Flow per share |
(diluted) .............................. $ 2.44 $ 1.72 | $ 1.16 $ 1.01 $ 6.32
|
EBITDAX (4) ................................. $ 51,494 $ 42,135 | $ 31,519 $ 29,038 $ 154,166
|
Weighted average common and dilutive |
potential common shares outstanding .... 17,003 17,152 | 17,225 17,218 17,150
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Prices: |
Oil ($/BBL) - Including hedges ......... $ 15.71 $ 15.44 | $ 16.85 $ 17.03 $ 16.24
Oil ($/BBL) - reference price (NYMEX) .. $ 28.73 $ 27.96 | $ 26.76 $ 22.75 $ 26.55
Gas ($/MCF) ............................ $ 13.26 $ 11.46 | $ 3.37 $ 2.65 $ 7.86
Gas ($/MCF) - reference price (NYMEX) .. $ 7.27 $ 4.78 | $ 2.79 $ 2.69 $ 4.38
|
Production: |
Oil (MBBL) ............................. 4,144 4,220 | 4,081 3,805 16,249
BBLS/D ................................. 46,045 46,366 | 44,356 41,356 44,517
Gas (MMCF) ............................. 3,824 2,959 | 3,137 3,318 13,238
MMCF/D ................................. 43 33 | 34 36 36
Liquids (MBBL) ......................... 44 51 | 42 40 177
|
MBOE - Including liquids .................... 4,825 4,763 | 4,648 4,398 18,632
|
Lease Operating Expense per BOE ............. $ 11.87 $ 10.30 | $ 8.62 $ 8.47 $ 9.86
|
General & Administrative Expense per BOE .... $ 1.51 $ 1.94 | $ 1.79 $ 1.77 $ 1.75
|
Fixed Charge Coverage Ratio ................. 4.0 3.5 | 2.6 2.3 3.1
|
Long-term Debt .............................. $ 409,702 $ 409,702 | $ 409,677 $ 452,830 $ 452,830
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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.
THIRD 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 quarters ended March 31, 2001 and June 30,
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.
CRUDE OIL PRODUCTION
We anticipate that our third quarter 2001 production will be between 4.0 and 4.2
million barrels (43,478 - 45,652 barrels per day) which incorporates two weeks
of downtime at the Point Pedernales Field, offshore California due to the
replacement of five flanges on the crude oil pipeline. This estimate also
includes downtime for pump repairs, and scheduled field maintenance. Of the
third quarter 2001 volume, approximately 85% will be derived from California,
14% 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 third quarter 2001 are expected to be between
$16.75 and $17.00 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.
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. Please note that swaps were
added in the second, third and fourth quarters in 2002.
CRUDE OIL HEDGES
SWAPS VOLUME... WTI PRICE
----- ------ ----------
3Q01 20,000 B/D $21.22 Bbl.
4Q01 15,500 B/D $22.95 Bbl.
1Q02 12,500 B/D $25.91 Bbl.
2Q02 2,000 B/D $23.50 Bbl.
3Q02 6,800 B/D $23.20 Bbl.
4Q02 5,000 B/D $23.90 Bbl.
CRUDE OIL HEDGES - CON'T
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 third quarter 2001 production will be between 3.0 and 3.2
Bcf (32.6 MMcfd - 34.8 MMcfd) which incorporates a reduction in natural gas
volume due to a delay in the mobilization of a drilling rig offshore California
and about a month downtime associated with the replacement of the carbon dioxide
unit at the Rincon Onshore Separation Facility (ROSF). The estimate also
includes two weeks of downtime at the Point Pedernales Field, offshore
California due to the replacement of five flanges on the crude oil pipeline. Of
this third quarter 2001 volume, approximately 92% will be derived from
California and 8% 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 third quarter 2001 are expected to be between $3.20
and $3.50 Mcf based on our assumption regarding the California price
differential versus the current NYMEX strip price. In July, the California basis
differential narrowed significantly versus the first half 2001. For the third
quarter 2001, our realized gas price estimate assumes a more normalized
California basis differential.
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.
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. Beginning in mid-December 2000 and
continuing into the first half 2001, 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. With the recent dramatic decline in
California gas prices, Nuevo restarted its cyclic steaming operations in August,
thereby reducing the amount of gas sold in the market. Should these lower
California gas prices continue to hold, Nuevo will consider restarting its steam
drive operations.
NATURAL GAS HEDGES
Nuevo does not have any of its natural gas production hedged.
LIQUIDS
We anticipate that our third quarter 2001 production will be between 41,000 and
43,000 barrels (446 and 467 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.
THIRD QUARTER 2001 TOTAL PRODUCTION
We anticipate that our third quarter 2001 production will be between 4.5 and 4.8
million BOE 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.
2001 TOTAL PRODUCTION
We anticipate that total production for 2001 will be between 18.5 and 18.8
MMBOE. This estimate incorporates about three weeks of oil production downtime
and about eight weeks of gas production downtime due to the failure of a carbon
dioxide treatment vessel at the Rincon Onshore Separation Facility (ROSF)
located in Ventura County, California. As of August 11, 2001, the ROSF facility
was operational and total production was restored. In addition, this estimate
incorporates the shutdown of production at the Point Pedernales Field, offshore
California from mid-September to year-end 2001 due to the replacement of five
flanges on the crude oil pipeline.
LEASE OPERATING EXPENSE (INCLUDES PRODUCTION AND AD VALOREM TAXES)
Nuevo uses natural gas to generate steam for its thermal production. Due to high
California gas costs and a reduction in steam usage which impacted production,
first half 2001 LOE averaged $11.09 BOE. We expect the third quarter 2001 LOE to
be between $8.40 and $8.80 BOE due to lower California gas prices combined with
the restarting of cyclic steaming in August.
DEPRECIATION, DEPLETION AND AMORTIZATION
We anticipate that the DD&A rate for the third quarter 2001 will be between
$3.65 and $3.85 BOE. Our forecasted DD&A rate has been revised downward based on
estimated SEC reserves at June 30, 2001.
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 third quarter 2001 should be
between $4.5 million and $6.0 million.
GENERAL AND ADMINISTRATIVE EXPENSE
We anticipate that the G&A rate for the third quarter 2001 will be between $1.75
and $1.85 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 the third quarter 2001 will be
between $10.0 million and $11.0 million.
TERM CONVERTIBLE SECURITIES (TECONS) - DIVIDEND EXPENSE
We expect our third quarter 2001 TECONS dividend expense to be $1.65 million.
INCOME TAXES
We expect our effective income tax rate for the third quarter 2001 to be 40%
(inclusive of applicable federal and state taxes) 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. On February 12, 2001, the Board authorized the repurchase of 1 million
shares of Nuevo common stock. As of June 30, 2001, approximately 1,007,700
shares remained authorized for repurchase at management's discretion under
existing authorizations. While the Company's policy is not to comment on the
status of the share repurchase program until the authorization(s) 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 (excluding acquisitions) for 2001 to be
approximately $152 million. This figure does not include deferred acquisition
costs, expected to be $8 - $12 million depending on final 2001 production levels
and average 2001 field price realizations on certain of our California
properties, arising from a contingent payment agreement entered into upon the
acquisition of the affected properties, as disclosed in our filings since the
acquisition. Pursuant to Generally Accepted Accounting Principles, such payment
will be accrued as capital in the fourth quarter once the size of the payment is
finally determined. It is expected to be paid in the first quarter 2002.
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.