<PAGE>
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2000
Commission File Number 1-10537
NUEVO ENERGY COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE 76-0304436
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
1021 Main Street, Suite 2100
Houston, Texas 77002
(Address of Principal Executive Offices) (Zip Code)
Registrant's telephone number, including area code: (713) 652-0706
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the Registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No____
-------
As of August 10, 2000, the number of outstanding shares of the Registrant's
common stock was 17,587,238.
<PAGE>
NUEVO ENERGY COMPANY
INDEX
<TABLE>
<CAPTION>
PAGE
NUMBER
<S> <C>
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
Condensed Consolidated Balance Sheets:
June 30, 2000 (Unaudited) and December 31, 1999................................... 3
Condensed Consolidated Statements of Operations (Unaudited):
Three and six months ended June 30, 2000 and June 30, 1999........................ 4
Condensed Consolidated Statements of Cash Flows (Unaudited):
Six months ended June 30, 2000 and June 30, 1999.................................. 6
Notes to Condensed Consolidated Financial Statements (Unaudited)................... 7
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations..... 14
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk................................ 26
PART II. OTHER INFORMATION......................................................................... 27
</TABLE>
2
<PAGE>
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
-----------------------------
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Amounts in Thousands, Except Share Data)
<TABLE>
<CAPTION>
June 30, 2000 December 31, 1999
------------- -----------------
ASSETS (Unaudited)
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents.............................. $ 13,122 $ 10,288
Accounts receivable.................................... 36,554 45,004
Product inventory...................................... 11,135 4,610
Prepaid expenses and other............................. 4,961 6,389
------------ ----------
Total current assets................................. 65,772 66,291
------------ ----------
PROPERTY AND EQUIPMENT, AT COST:
Land................................................... 51,017 51,017
Oil and gas properties (successful efforts method)..... 1,045,774 1,002,779
Gas plant facilities................................... 12,020 12,140
Other facilities....................................... 12,595 11,874
------------ ----------
1,121,406 1,077,810
Accumulated depreciation, depletion and amortization... (461,191) (429,349)
------------ ----------
660,215 648,461
------------ ----------
DEFERRED TAX ASSETS, NET................................ 22,971 24,005
OTHER ASSETS............................................ 20,284 21,273
------------ ----------
$ 769,242 $ 760,030
============ ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable...................................... $ 14,667 $ 20,492
Accrued interest...................................... 2,474 2,353
Accrued liabilities................................... 40,304 37,755
Current maturities of long-term debt.................. - 750
------------ ----------
Total current liabilities......................... 57,445 61,350
------------ ----------
LONG-TERM DEBT, NET OF CURRENT MATURITIES............... 363,227 340,750
OTHER LONG-TERM LIABILITIES............................. 8,447 9,292
CONTINGENCIES
COMPANY-OBLIGATED MANDATORILY
REDEEMABLE CONVERTIBLE PREFERRED
SECURITIES OF NUEVO FINANCING I......................... 115,000 115,000
STOCKHOLDERS' EQUITY:
Common stock, $.01 par value, 50,000,000 shares
authorized, 20,589,072 and 20,437,371 shares
issued at June 30, 2000 and December 31, 1999,
respectively......................................... 206 204
Additional paid-in capital............................ 360,397 357,855
Treasury stock, at cost, 3,006,452 and 2,430,074
shares, at June 30, 2000 and December 31, 1999,
respectively......................................... (61,935) (49,605)
Stock held by benefit trust, 161,026 and 75,904 shares,
at June 30, 2000 and December 31, 1999,
respectively......................................... (3,395) (3,184)
Deferred stock compensation........................... (233) (216)
Accumulated deficit................................... (69,917) (71,416)
------------ ----------
Total stockholders' equity........................ 225,123 233,638
------------ ----------
$ 769,242 $ 760,030
============ ==========
</TABLE>
See accompanying notes to condensed consolidated financial statements.
3
<PAGE>
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in Thousands, Except per Share Data)
Three Months Ended June 30,
---------------------------
2000 1999
------- --------
REVENUES:
Oil and gas revenues............................ $ 72,599 $ 52,876
Gain on sale of assets, net..................... 366 (1,387)
Interest and other income....................... 195 1,371
-------- --------
73,160 52,860
-------- --------
COSTS AND EXPENSES:
Lease operating expenses........................ 34,273 30,298
Exploration costs............................... 1,488 7,874
Depreciation, depletion and amortization........ 15,582 22,937
General and administrative expenses............. 4,101 3,367
Outsourcing fees................................ 3,430 3,636
Interest expense................................ 8,517 8,401
Dividends on Guaranteed Preferred
Beneficial Interests in Company's
Convertible Debentures (TECONS)............... 1,653 1,653
Other expense................................... 2,687 457
-------- --------
71,731 78,623
-------- --------
Income (loss) before income taxes................ 1,429 (25,763)
Provision (benefit) for income taxes............. 575 (10,205)
-------- --------
NET INCOME (LOSS)................................ $ 854 $(15,558)
======== ========
EARNINGS (LOSS) PER SHARE:
Basic:
Earnings (loss) per common share................. $ 0.05 $ (0.78)
======== ========
Weighted average common shares outstanding....... 17,587 19,853
======== ========
DILUTED:
Earnings (loss) per common share................. $ 0.05 $ (0.78)
======== ========
Weighted average common and dilutive potential
common shares outstanding........................ 17,939 19,853
======== ========
See accompanying notes to condensed consolidated financial statements.
4
<PAGE>
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in Thousands, Except per Share Data)
Six Months Ended June 30,
---------------------------
2000 1999
------- --------
REVENUES:
Oil and gas revenues............................ $143,328 $ 96,340
Gain on sale of assets, net..................... 506 80,312
Interest and other income....................... 821 2,851
-------- --------
144,655 179,503
-------- --------
COSTS AND EXPENSES:
Lease operating expenses........................ 65,384 60,212
Exploration costs............................... 4,742 9,999
Depreciation, depletion and amortization........ 31,823 46,257
General and administrative expenses............. 9,473 7,199
Outsourcing fees................................ 6,763 6,846
Interest expense................................ 16,807 16,400
Dividends on Guaranteed Preferred
Beneficial Interests in Company's
Convertible Debentures (TECONS)............... 3,306 3,306
Other expense................................... 3,847 2,979
-------- --------
142,145 153,198
-------- --------
Income before income taxes....................... 2,510 26,305
Provision for income taxes....................... 1,011 10,521
-------- --------
NET INCOME....................................... $ 1,499 $ 15,784
======== ========
EARNINGS PER SHARE:
Basic:
Earnings per common share........................ $ 0.08 $ 0.80
======== ========
Weighted average common shares outstanding....... 17,701 19,848
======== ========
DILUTED:
Earnings per common share........................ $ 0.08 $ 0.79
======== ========
Weighted average common and dilutive potential
common shares outstanding........................ 18,074 19,915
======== ========
See accompanying notes to condensed consolidated financial statements.
5
<PAGE>
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in Thousands)
<TABLE>
<CAPTION>
Six Months Ended
June 30,
--------------------------
2000 1999
---------- ------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................. $ 1,499 $ 15,784
Adjustments to reconcile net income to
net cash provided by/(used in) operating activities:
Depreciation, depletion and amortization.............. 31,823 46,257
Gain on sale of assets, net........................... (506) (80,312)
Dry hole costs........................................ 89 7,297
Amortization of other costs........................... 903 811
Deferred taxes........................................ 1,382 5,521
Mark to market of deferred compensation plan.......... 24 111
Mark to market of liability management swap........... 371 -
Other................................................. 66 120
-------- ---------
35,651 (4,411)
Changes in assets and liabilities:
Accounts receivable.................................... 8,450 (1,459)
Accounts payable and accrued liabilities............... (3,152) (5,606)
Other.................................................. (4,621) (1,680)
-------- ---------
NET CASH PROVIDED BY/(USED IN) OPERATING ACTIVITIES........ 36,328 13,156
-------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties...................... (43,609) (35,497)
Acquisitions of oil and gas properties................... - (61,416)
Additions to gas plant facilities........................ (126) (674)
Additions to other facilities............................ (721) (2,434)
Proceeds from sales of properties........................ 1,297 199,663
-------- ---------
NET CASH (USED IN)/PROVIDED BY INVESTING ACTIVITIES........ (43,159) 99,642
-------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings................................. 32,500 120,090
Deferred financing costs................................. (1,634) -
Payments of long-term debt............................... (10,773) (160,340)
Treasury stock purchases................................. (12,540) -
Proceeds from issuance of common stock............... 2,112 -
-------- ---------
NET CASH PROVIDED BY/(USED IN) FINANCING ACTIVITIES.... 9,665 (40,250)
-------- ---------
Net increase in cash and cash equivalents........... 2,834 46,236
Cash and cash equivalents at beginning of period.... 10,288 7,403
-------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD............ $ 13,122 $ 53,639
======== =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of amounts capitalized).............. $ 15,782 $ 15,646
Income taxes....................................... $ - $ 2,250
</TABLE>
See accompanying notes to condensed consolidated financial statements.
6
<PAGE>
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
------------------------------------------
The accompanying unaudited condensed consolidated financial statements have
been prepared in accordance with the rules and regulations of the Securities
and Exchange Commission and, therefore, do not include all disclosures
required by generally accepted accounting principles. However, in the
opinion of management, these statements include all adjustments, which are of
a normal recurring nature, necessary to present fairly the financial position
at June 30, 2000 and December 31, 1999 and the results of operations and
changes in cash flows for the periods ended June 30, 2000 and 1999. These
financial statements should be read in conjunction with the consolidated
financial statements and notes to consolidated financial statements in the
1999 Form 10-K of Nuevo Energy Company (the "Company").
USE OF ESTIMATES
----------------
In order to prepare these financial statements in conformity with generally
accepted accounting principles, management of the Company has made a number
of estimates and assumptions relating to the reporting of assets and
liabilities and the disclosure of contingent assets and liabilities, as well
as reserve information, which affects the depletion calculation. Actual
results could differ from those estimates.
COMPREHENSIVE INCOME
--------------------
Comprehensive income includes net income and all changes in other
comprehensive income including, among other things, foreign currency
translation adjustments, and unrealized gains and losses on certain
investments in debt and equity securities. There are no differences between
comprehensive income (loss) and net income (loss) for the periods presented.
DERIVATIVE FINANCIAL INSTRUMENTS
--------------------------------
The Company utilizes derivative financial instruments to reduce its exposure
to changes in the market prices of crude oil and natural gas. Commodity
derivatives utilized as hedges include futures, swap and option contracts,
which are used to hedge crude oil and natural gas prices. Basis swaps are
sometimes used to hedge the basis differential between the derivative
financial instrument index price and the commodity field price. In order to
qualify as a hedge, price movements in the underlying commodity derivative
must be highly correlated with the hedged commodity. Settlement of gains and
losses on price swap contracts are realized monthly, generally based upon the
difference between the contract price and the average closing New York
Mercantile Exchange ("NYMEX") price and are reported as a component of oil
and gas revenues and operating cash flows in the period realized.
Gains and losses on option and futures contracts that qualify as a hedge of
firmly committed or anticipated purchases and sales of oil and gas
commodities are deferred on the balance sheet and recognized in income and
operating cash flows when the related hedged transaction occurs. Premiums
paid on option contracts are deferred in other assets and amortized into oil
and gas revenues over the terms of the respective option contracts. Gains or
losses attributable to the termination of a derivative financial instrument
are deferred on the balance sheet and recognized in revenue when the hedged
crude oil and natural gas are sold. There were no such deferred gains or
losses at June 30, 2000 or December 31, 1999. Gains or losses on derivative
financial instruments that do not qualify as a hedge are recognized in income
currently.
As a result of hedging transactions, oil and gas revenues were reduced by
$24.8 million and $9.0 million in the second quarter of 2000 and 1999,
respectively. For the first six months of 2000 and 1999, oil and gas
revenues were reduced by $51.3 million and $8.8 million, respectively, as a
result of hedging transactions.
In 1999, the Company entered into a swap arrangement with a major financial
institution that effectively converts the interest rate on $16.4 million
notional amount of the 9 1/2 % Senior Subordinated Notes due 2008 ("Notes")
to a variable LIBOR-based rate. In February 2000, this arrangement was
extended through February 26, 2001. Based on LIBOR rates in effect at June
30, 2000, this amounted to a net reduction in the carrying cost of the Notes
from 9 1/2 % to 7.03%, or 247 basis points. In addition, the swap
arrangement also effectively
7
<PAGE>
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
sets the price at which the Company can repurchase these Notes. For the three
and six months ended June 30, 2000, the Company recorded market adjustments
of $410,000 and ($371,000), respectively, related to the change in the fair
value of the Notes. In July 2000, a portion of this swap arrangement was
settled on a notional amount of $5.0 million of the Notes. The Company will
record a gain of approximately $100,000 as a result of this settlement.
For 2000, the Company entered into swap contracts on 16,500 barrels of oil
per day ("BOPD"), at an average West Texas Intermediate ("WTI") price of
$17.94 per barrel. The Company also entered into collars on an additional
16,500 BOPD, with a floor of $16.00 per barrel and ceiling of $21.21 per
barrel. This production is hedged based on a fixed NYMEX price. In May 2000,
in connection with the sale of certain non-core California oil and gas
properties (see Note 9), the Company unwound the $21.21 per barrel ceiling on
2,800 BOPD for the period May 2000 through December 2000. Also for the year
2000, the Company has entered into basis swaps on 3,000 BOPD of its
production in the Congo, hedging the basis differential between No. 6 fuel
oil and WTI at an average differential of $1.88 per barrel. At June 30, 2000,
the market value of the hedge positions was a loss of approximately $50.1
million.
For 2001, the Company has entered into swap arrangements on 26,000 BOPD for
the first quarter at an average WTI price of $19.52 per barrel, for the
second quarter on 25,000 BOPD at an average WTI price of $19.54 per barrel,
for the third quarter on 20,000 BOPD at an average WTI price of $21.22 per
barrel, and for the fourth quarter on 15,500 BOPD at an average WTI price of
$22.95 per barrel. At June 30, 2000, the market value of these swaps was a
loss of $40.7 million. These agreements expose the Company to counterparty
credit risk to the extent that the counterparty is unable to meet its
settlement commitments to the Company.
RECENT ACCOUNTING PRONOUNCEMENTS
--------------------------------
In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities".
This statement, as amended by SFAS No. 137 and SFAS No. 138, establishes
standards of accounting for and disclosures of derivative instruments and
hedging activities. This statement requires all derivative instruments to be
carried on the balance sheet at fair value and is effective for the Company
beginning January 1, 2001. The Company has not yet determined the impact of
this statement on its financial condition or results of operations.
RECLASSIFICATIONS
-----------------
Certain reclassifications of prior year amounts have been made to conform to
the current presentation.
2. PROPERTY AND EQUIPMENT
----------------------
The Company utilizes the successful efforts method of accounting for its
investments in oil and gas properties. Under successful efforts, oil and gas
lease acquisition costs and intangible drilling costs associated with
exploration efforts that result in the discovery of proved reserves and costs
associated with development drilling, whether or not successful, are
capitalized when incurred. When a proved property is sold, ceases to produce
or is abandoned, a gain or loss is recognized. When an entire interest in an
unproved property is sold for cash or cash equivalent, gain or loss is
recognized, taking into consideration any recorded impairment. When a
partial interest in an unproved property is sold, the amount received is
treated as a reduction of the cost of the interest retained.
Unproved leasehold costs are capitalized pending the results of exploration
efforts. Significant unproved leasehold costs are reviewed periodically and
a loss is recognized to the extent, if any, that the cost of the property has
been impaired. Exploration costs, including geological and geophysical
expenses, exploratory dry holes and delay rentals, are charged to expense as
incurred.
Costs of productive wells, development dry holes and productive leases are
capitalized and depleted on a unit-of-production basis over the life of the
remaining proved reserves. Capitalized drilling costs are depleted on a
8
<PAGE>
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
unit-of-production basis over the life of the remaining proved developed
reserves. Estimated costs (net of salvage value) of dismantlement,
abandonment and site remediation are computed by the Company's independent
reserve engineers and are included when calculating depreciation and
depletion using the unit-of-production method.
The Company reviews proved oil and gas properties on a depletable unit basis
whenever events or circumstances indicate that the carrying value of those
assets may not be recoverable. For each depletable unit determined to be
impaired, an impairment loss equal to the difference between the carrying
value and the fair value of the depletable unit is recognized. Fair value,
on a depletable unit basis, is estimated to be the present value of the
undiscounted expected future net revenues computed by application of
estimated future oil and gas prices, production and expenses, as determined
by management, to estimated future production of oil and gas reserves over
the economic life of the reserves. If the carrying value exceeds the
undiscounted future net revenues, an impairment is recognized equal to the
difference between the carrying value and the discounted estimated future net
revenues of that depletable unit. The Company considers all proved reserves
and commodity pricing based on available market information in its estimate
of future net revenues.
3. DEFERRED TAX ASSETS
-------------------
The Company has deferred tax assets, net of valuation allowances, of $23.0
million and $24.0 million as of June 30, 2000 and December 31, 1999,
respectively. The Company believes that sufficient future taxable income will
be generated and has concluded that these net deferred tax assets will more
likely than not be realized.
9
<PAGE>
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
4. INDUSTRY SEGMENT INFORMATION
----------------------------
As of June 30, 2000, the Company's oil and gas exploration and production
operations were concentrated primarily in two geographic regions:
domestically, onshore and offshore California, and internationally, offshore
the Republic of Congo in West Africa (the "Congo").
For the Six Months
Ended June 30,
---------------------
2000 1999
----------- --------
(amounts in thousands)
Sales to unaffiliated customers:
Oil and gas - Domestic................... $ 121,354 $ 85,425
Oil and gas - International.............. 21,974 10,915
-------- --------
Total sales................................. 143,328 96,340
Gain on sale of assets, net.............. 506 80,312
Other revenues........................... 821 2,851
--------- --------
Total revenues.............................. $ 144,655 $179,503
========= ========
Operating profit before income taxes:
Oil and gas - Domestic (a)............... $ 35,399 $ 61,516
Oil and gas - International.............. 7,219 (806)
-------- --------
42,618 60,710
Unallocated corporate expenses.............. 19,995 14,699
Interest expense............................ 16,807 16,400
Dividends on TECONS......................... 3,306 3,306
-------- --------
Income before income taxes............... $ 2,510 $ 26,305
======== ========
Depreciation, depletion and amortization:
Oil and gas - Domestic................... $ 26,854 $ 41,651
Oil and gas - International.............. 4,236 3,855
Other.................................... 733 751
-------- --------
$ 31,823 $ 46,257
======== ========
(a) Includes an $80.3 million gain on sale of the East Texas gas
properties for the six months ended June 30, 1999.
5. LONG-TERM DEBT
--------------
Long-term debt consists of the following (amounts in thousands):
June 30, December 31,
2000 1999
--------- -----------
9 1/2% Senior Subordinated Notes due 2008........... $ 257,310 $ 257,310
9 1/2% Senior Subordinated Notes due 2006........... 2,417 2,440
Bank credit facility (a)............................ 103,500 81,000
OPIC credit facility................................ - 750
--------- ----------
Total debt..................................... 363,227 341,500
Less: current maturities............................ - (750)
--------- ----------
Long-term debt...................................... $ 363,227 $ 340,750
========= ==========
(a) Nuevo's Third Restated Credit Agreement dated June 7, 2000, provides for
secured revolving credit availability of up to $410.0 million (subject to a
semi-annual borrowing base determination) from a bank group led by Bank of
America, N.A., Bank One, NA, and Bank of Montreal, until its expiration on
June 7,
10
<PAGE>
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
2005. The borrowing base on the Company's credit facility is
subject to a semi-annual borrowing base determination on March 1 and
September 1 of each year, beginning September 1, 2000. The borrowing base
at June 30, 2000, was $300.0 million. The Company was in compliance with
all covenants as of June 30, 2000, and does not anticipate any issues of
non-compliance arising in the foreseeable future. At June 30, 2000,
outstanding borrowings under the revolving credit agreement and an
uncommitted line of credit were $103.5 million. Accordingly, $196.5
million of credit capacity was unused and available at June 30, 2000.
6. EARNINGS PER SHARE COMPUTATION
------------------------------
SFAS No. 128 requires a reconciliation of the numerator (income) and
denominator (shares) of the basic earnings per share ("EPS") computation to
the numerator and denominator of the diluted EPS computation. In the three-
month period ended June 30, 1999, there were no potential dilutive common
shares. The Company's reconciliation is as follows (amounts in thousands):
<TABLE>
<CAPTION>
For the Three Months Ended June 30,
------------------------------------------------------
2000 1999
----------------------- ----------------------------
Income Shares Income Shares
---------- ---------- ------------ ------------
<S> <C> <C> <C> <C>
Earnings per Common share - Basic........................ $ 854 17,587 $ (15,558) 19,853
Effect of dilutive securities:
Stock options............................................ --- 352 --- ---
---------- ---------- ------------ ------------
Earnings per Common share - Diluted...................... $ 854 17,939 $ (15,558) 19,853
========== ========== ============ ============
</TABLE>
<TABLE>
<CAPTION>
For the Six Months Ended June 30,
------------------------------------------------------
2000 1999
----------------------- ----------------------------
Income Shares Income Shares
---------- ---------- ------------ ------------
<S> <C> <C> <C> <C>
Earnings per Common share - Basic........................ $ 1,499 17,701 $ 15,784 19,848
Effect of dilutive securities:
Stock options............................................ --- 373 --- 67
---------- ---------- ------------ ------------
Earnings per Common share - Diluted...................... $ 1,499 18,074 $ 15,784 19,915
========== ========== ============ ============
</TABLE>
7. CONTINGENCIES AND OTHER MATTERS
-------------------------------
The Company had been named as a defendant in Gloria Garcia Lopez and Husband,
Hector S. Lopez, Individually, and as successors to Galo Land & Cattle
Company v. Mobil Producing Texas & New Mexico, et al. in the 79th Judicial
District Court of Brooks County, Texas. On June 9, 2000, the parties entered
into a memorandum of settlement agreement, pursuant to which the lawsuit
would be dismissed (subject to and upon execution of final settlement
documents), the defendants would pay the plaintiffs $12.0 million and the
lease agreement would be amended. Nuevo's working interest in these
properties is 20%, and its share of the settlement payment is approximately
$2.4 million.
The Company has been named as a defendant in certain other lawsuits
incidental to its business. Management does not believe that the outcome of
such litigation will have a material adverse impact on the Company's
operating results or financial condition. However, these actions and claims
in the aggregate seek substantial damages against the Company and are subject
to the inherent uncertainties present in any litigation. The Company is
defending itself vigorously in all such matters.
In March 1999, the Company discovered that a non-officer employee had
fraudulently authorized and diverted for personal use Company funds totaling
$5.9 million, $1.6 million in 1999 and the remainder in 1998, that were
intended for international exploration. The Board of Directors engaged a
Certified Fraud Examiner to conduct an in-depth review of the fraudulent
transactions. The investigation confirmed that only one employee was
involved in the matter and that all misappropriated funds were identified.
The Company has reviewed and,
11
<PAGE>
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
where appropriate, strengthened its internal control procedures. As a result
of ongoing negotiations, the Company is confident that it will recoup a
portion of the loss.
In September 1997, there was a spill of crude oil into the Santa Barbara
Channel from a pipeline that connects the Company's Point Pedernales field
with shore-based processing facilities. The volume of the spill was
estimated to be 163 barrels of oil. The costs of the clean up and the cost
to repair the pipeline either have been or are expected to be covered by
insurance, less the Company's deductibles, which in total are $120,000.
Repairs were completed by the end of 1997, and production recommenced in
December 1997. The Company also has exposure to costs that may not be
recoverable from insurance, including certain fines, penalties, and damages.
Such costs are not quantifiable at this time, but are not expected to be
material to the Company's operating results, financial condition or
liquidity.
The Company's international investments involve risks typically associated
with investments in emerging markets such as an uncertain political,
economic, legal and tax environment and expropriation and nationalization of
assets. In addition, if a dispute arises in its foreign operations, the
Company may be subject to the exclusive jurisdiction of foreign courts or may
not be successful in subjecting foreign persons to the jurisdiction of the
United States. The Company attempts to conduct its business and financial
affairs so as to protect against political and economic risks applicable to
operations in the various countries where it operates, but there can be no
assurance that the Company will be successful in so protecting itself. A
portion of the Company's investment in the Republic of Congo in West Africa
("Congo") is insured through political risk insurance provided by the
Overseas Private Investment Corporation ("OPIC"). The Company will consider
its options for political risk insurance in the Republic of Ghana in West
Africa ("Ghana") as it evaluates business opportunities.
In connection with their respective acquisitions of two subsidiaries owning
interests in the Yombo field offshore West Africa (each a "Congo
subsidiary"), the Company and a wholly-owned subsidiary of CMS NOMECO Oil &
Gas Co. ("CMS") agreed with the seller not to claim certain tax losses
incurred by such subsidiaries prior to the acquisitions. Pursuant to the
agreement, the Company and CMS may be liable to the seller for the recapture
of these tax losses utilized by the seller in years prior to the acquisitions
if certain triggering events occur. A triggering event will not occur if a
subsequent purchaser enters into certain agreements specified in the
consolidated return regulations intended to ensure that such losses will not
be claimed. The Company's potential direct liability could be as much as
$48.5 million if a triggering event with respect to the Company occurs, and
the Company believes that CMS's liability (for which the Company would be
jointly liable with an indemnification right against CMS) could be as much as
$64.1 million. The Company does not expect a triggering event to occur with
respect to it or CMS and does not believe the agreement will have a material
adverse effect upon the Company.
8. CONTINGENT PAYMENT AND PRICE SHARING AGREEMENTS
-----------------------------------------------
In connection with the acquisition from Unocal in 1996 of the properties
located in California, the Company is obligated to make a contingent payment
for the years 1998 through 2004 if oil prices exceed thresholds set forth in
the agreement with Unocal. The contingent payment will equal 50% of the
difference between the actual average annual price received on a field-by-
field basis (capped by a maximum price) and a minimum price, less ad valorem
and production taxes, multiplied by the actual number of barrels of oil sold
that are produced from the properties acquired from Unocal during the
respective year. The minimum price of $17.75 per Bbl. under the agreement
(determined based on near month of delivery of WTI crude oil on the NYMEX) is
escalated at 3% per year and the maximum price of $21.75 per Bbl. on the
NYMEX is escalated at 3% per year. Minimum and maximum prices are reduced to
reflect the field level price by subtracting a fixed differential established
for each field. The reduction was established at approximately the
differential between actual sales prices and NYMEX prices in effect in 1995
($4.34 per Bbl. weighted average for all the properties acquired from
Unocal). The Company accumulates credits to offset the contingent payment
when prices are $.50 per Bbl. or more below the minimum price. The Company
computes this calculation annually and had accumulated $30.8 million in price
credits as of December 31, 1999, which will be used to reduce future amounts
owed under the contingent payment.
12
<PAGE>
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
In connection with the acquisition of the Congo properties in 1995, the
Company entered into a price sharing agreement with the seller. Under the
terms of the agreement, if the average price received for the oil production
during the year is greater than the benchmark price established by the
agreement, then the Company is obligated to pay the seller 50% of the
difference between the benchmark price and the actual price received, for
all the barrels associated with this acquisition. The benchmark price for
2000 is $15.19 per Bbl. The benchmark price increases each year based on the
increase in the Consumer Price Index. For 2000, the effect of this agreement
is that Nuevo is entitled to receive the pricing upside above $15.19 per
Bbl. on approximately 56% of its Congo production.
The Company acquired a 12% working interest in the Point Pedernales oil
field from Unocal in 1994 and the remainder of its interest in this field
from Torch Energy Advisors Inc. ("Torch") in 1996. The Company is entitled
to all revenue proceeds up to $9.00 per Bbl., with the excess over $9.00 per
Bbl., if any, shared among the Company and the original owners from whom
Torch acquired its interest. For 2000, the effect of this agreement is that
Nuevo is entitled to receive the pricing upside above $9.00 per Bbl. on
approximately 34% of its net Point Pedernales production.
9. DIVESTITURES
------------
In May 2000, the Company sold certain of its non-core California properties
for proceeds of approximately $4.6 million. The Company reclassified these
assets to assets held for sale during the third quarter of 1999, at which
time it discontinued depleting and depreciating these assets. In connection
with this sale, the Company unwound hedges of 2,800 BOPD for the period May
2000 through December 2000 (see Note 1).
10. SHARE REPURCHASES
-----------------
In August 1999, the Company implemented a share repurchase program, pursuant
to the Board of Directors' authorizations to repurchase up to a total of
3,616,600 shares at times and at prices deemed attractive by management. As
of June 30, 2000, the Company had repurchased 2,660,600 shares of its common
stock in open market transactions at an average purchase price, including
commissions, of $16.79 per share.
13
<PAGE>
NUEVO ENERGY COMPANY
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
FORWARD LOOKING STATEMENTS
--------------------------
This document includes "forward looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended (the "Securities Act"),
and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act"). All
statements other than statements of historical facts included in this
document, including without limitation, statements under "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
regarding the Company's financial position, estimated quantities and net
present values of reserves, business strategy, plans and objectives of
management of the Company for future operations and covenant compliance, are
forward-looking statements. Although the Company believes that the
assumptions upon which such forward-looking statements are based are
reasonable, it can give no assurances that such assumptions will prove to
have been correct. Important factors that could cause actual results to
differ materially from the Company's expectations ("Cautionary Statements")
are disclosed below and elsewhere in this document and in the Company's
Annual Report on Form 10-K and other filings made with the Securities and
Exchange Commission. All subsequent written and oral forward-looking
statements attributable to the Company or persons acting on its behalf are
expressly qualified by the Cautionary Statements.
Capital Resources and Liquidity
-------------------------------
Since inception, the Company has expanded its operations through a series of
disciplined, low-cost acquisitions of oil and gas properties and the
subsequent exploitation and development of these properties. The Company has
complemented these efforts with strategic divestitures and an opportunistic
exploration program, which provides exposure to prospects that have the
potential to add substantially to the growth of the Company. The funding of
these activities has historically been provided by operating cash flows, bank
financing, private and public placements of debt and equity securities,
property divestitures and joint ventures with industry participants. Net
cash provided by (used in) operating activities was $36.3 million and $(13.2)
million for the six months ended June 30, 2000 and 1999, respectively. The
Company invested $43.6 million and $35.5 million in oil and gas properties
for the six months ended June 30, 2000 and 1999, respectively.
The current borrowing base on the Company's credit facility is $300.0
million. At June 30, 2000, outstanding borrowings under the revolving credit
agreement and an uncommitted line of credit were $103.5 million. Accordingly,
$196.5 million of credit capacity was unused and available at June 30, 2000.
At June 30, 2000, the Company had working capital of $8.3 million.
On June 7, 2000, the Company entered into its Third Restated Credit
Agreement, which provides for secured revolving credit availability of up to
$410.0 million (subject to a semi-annual borrowing base determination) from a
bank group led by Bank of America, N.A., Bank One, NA, and Bank of Montreal,
until its expiration on June 7, 2005. The borrowing base on the Company's
credit facility is subject to a semi-annual borrowing base determination on
March 1 and September 1 of each year, beginning September 1, 2000. The
borrowing base at June 30, 2000, was $300.0 million. The Company was in
compliance with all covenants as of June 30, 2000, and does not anticipate
any issues of non-compliance arising in the foreseeable future. Subsequent
semi-annual borrowing base redeterminations will require the consent of banks
holding 60% of the total facility commitments, while an increase in the
borrowing base will require the consent of banks holding 66 2/3% of the total
facility commitments.
In July 2000, the Company announced that it no longer expects that its Brea
Highlands residential development will receive entitlement from the City of
Brea, California by the end of 2000. The Company had planned to sell or
joint venture this property upon completion of the entitlement process. This
expected delay results from a political initiative that, if passed, will
subject certain future development projects, such as Brea Highlands, to a
public vote. Because of this delay, the Company plans to defer $20.0 million
of its $140.0 million 2000 capital budget. The revised 2000 capital budget
of $120.0 million is designed to preserve the Company's financial condition
and liquidity.
The Company believes its cash flow from operations and available financing
sources are sufficient to meet its obligations as they become due and to
finance its exploration and development programs.
14
<PAGE>
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
CAPITAL EXPENDITURES
--------------------
As mentioned above, the Company plans to defer $20.0 million of its $140.0
million 2000 capital budget, as a result of expected delays in the potential
sale or joint venture of a real estate development. Under the revised 2000
capital budget of $120.0 million, the Company anticipates spending
approximately $58.0 million on development activities and approximately $15.0
million on exploration activities and business development projects during
the remainder of the year.
Exploration and development expenditures, including amounts expensed under
the successful efforts method, for the first six months of 2000 and 1999 are
as follows (amounts in thousands):
For the Six Months Ended
June 30,
------------------------
2000 1999
--------- --------
Domestic $ 44,063 $ 17,274
International 4,515 19,421
--------- --------
Total $ 48,578 $ 36,695
========= ========
The following is a description of significant exploration and development
activity during the first six months of 2000.
Exploration Activity
Domestic
---------
There was no significant activity during the first half of 2000.
International
-------------
In the first half of 2000, the Company completed its acquisition and
processing of a 3-D seismic survey across the Eastern portion of its Accra-
Keta concession offshore the Republic of Ghana in West Africa ("Ghana"). This
survey extends from the outer shelf, across the slope, and into the deepwater
regions of the block. The Company currently plans to drill its first
exploratory well on the concession late this year.
In June 2000, the Company acquired interests in two exploration permits in
the Republic of Tunisia, North Africa, that offer large reserve potential
within world-class proven hydrocarbon trends and add 1.3 million acres to the
Company's international portfolio. The first of these permits is the
171,000-acre Alyane Permit located offshore Tunisia in the Gulf of Gabes. The
Company will own a 100% interest and act as operator of the block. The Alyane
Permit lies directly within the prolific nummulite limestone trend where many
of Tunisia's and Libya's largest fields have been discovered. These fields,
which include, among others, Hasdrubal, Salambo, Bouri and Ashtart, have
estimated recoverable reserves which total over 1.5 billion barrels of oil
equivalent.
The Convention and Joint Venture Agreement for the Alyane Permit call for an
initial term of four years, followed by two optional three-year terms.
Nuevo's work commitment requires shooting 3-D seismic and drilling one
exploratory well on the Alyane Permit in the initial term. The Company plans
to explore the Alyane Permit aggressively and will acquire 3-D seismic data
in mid 2001 with the aim of drilling its first exploratory well in 2002.
Nuevo anticipates formal government approval of the Convention and Joint
Venture Agreement in September 2000.
Nuevo has also acquired a 10.42% interest from Bligh Tunisia Inc. in the 1.1-
million-acre Anaguid Permit located onshore southern Tunisia in the Ghadames
Basin. Operated by Anadarko Petroleum Company, this permit is on trend with
Anadarko's prolific Hassi Berkine complex located to the west in Algeria.
Under the
15
<PAGE>
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
current work commitment, the partners must drill one exploration well on the
Anaguid Permit by December 2001. In addition, the partners will reprocess all
existing seismic data and acquire new 2-D seismic data during 2000. Following
the expiration of the current work commitment term in December 2001, the
final renewal phase requires the drilling of one exploration well on the
Anaguid Permit during the 2 1/2-year term. Nuevo expects to receive
government approval of this acquisition in September 2000.
In addition to acquiring its interests in the Anaguid and Alyane Permits,
Nuevo has increased its existing 17.5% interest in the 900,000-acre Fejaj
Permit onshore Tunisia by acquiring an additional 20% interest from Bligh
Tunisia Inc. Nuevo and its partners plan to re-enter and deepen the Chott
Fejaj #3 well on the Fejaj Permit to test a sub-salt prospect. The Chott
Fejaj #3 well was drilled initially to the top of salt in 1998.
Development Activity
Domestic
--------
The Company drilled a total of 103 development wells in the first half of
2000, most of which relate to the interests acquired from Texaco in 1999.
The Company completed the first phase of its development-drilling program on
its Cymric lease acquired from Texaco, which included drilling 40 wells. The
Company began the second phase of this development program in June 2000,
which includes drilling an additional 60 wells. The Company expects this
program to be completed by the end of first quarter 2001. The wells drilled
to date are currently producing at a combined rate of 3,000 barrels of oil
per day ("BOPD"). In total, the Company drilled 54 wells on its Cymric lease
(four of which were horizontal wells), 17 wells on its Belridge lease (seven
of which were horizontal wells), and 29 wells at Midway Sunset.
Additionally, 49 injectors have been drilled to support the production from
these fields. In addition to the development activity at Cymric, the Company
successfully drilled two offshore wells at its Huntington Beach property.
These two wells have been completed and are producing 350 BOPD.
A significant facility expansion is underway at the Brea Olinda field. The
Company had flared approximately 2.5 MMCF of natural gas per day, due to the
lack of a gas market. In the second quarter of 2000, the Company completed
the installation of its first self-generation unit, which utilizes the gas
and converts it to electricity to supply all of the field electrical needs as
well as provides excess electricity for sale. The completion of the self-
generation project should result in significant cost savings for the Brea
Olinda property. A second unit should be installed and online by year-end
2000. Also, the Company is currently constructing a water plant at its
Cymric Field that will provide a long-term source of water to be used in the
Company's steam operations and help reduce expenses in the long-term.
International
-------------
There was no significant activity during the first half of 2000.
DERIVATIVE FINANCIAL INSTRUMENTS
--------------------------------
The Company utilizes derivative financial instruments to reduce its exposure
to changes in the market prices of crude oil and natural gas. Commodity
derivatives utilized as hedges include futures, swap and option contracts,
which are used to hedge crude oil and natural gas prices. Basis swaps are
sometimes used to hedge the basis differential between the derivative
financial instrument index price and the commodity field price. In order to
qualify as a hedge, price movements in the underlying commodity derivative
must be highly correlated with the hedged commodity. Settlement of gains and
losses on price swap contracts are realized monthly, generally based upon the
difference between the contract price and the average closing New York
Mercantile Exchange ("NYMEX") price and are reported as a component of oil
and gas revenues and operating cash flows in the period realized.
Gains and losses on option and futures contracts that qualify as a hedge of
firmly committed or anticipated purchases and sales of oil and gas
commodities are deferred on the balance sheet and recognized in income and
operating cash flows when the related hedged transaction occurs. Premiums
paid on option contracts are deferred in other assets and amortized into oil
and gas revenues over the terms of the respective option
16
<PAGE>
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
contracts. Gains or losses attributable to the termination of a derivative
financial instrument are deferred on the balance sheet and recognized in
revenue when the hedged crude oil and natural gas are sold. There were no
such deferred gains or losses at June 30, 2000 or December 31, 1999. Gains or
losses on derivative financial instruments that do not qualify as a hedge are
recognized in income currently.
As a result of hedging transactions, oil and gas revenues were reduced by
$24.8 million and $9.0 million in the second quarter of 2000 and 1999,
respectively. For the first six months of 2000 and 1999, oil and gas
revenues were reduced by $51.3 million and $8.8 million, respectively, as a
result of hedging transactions.
In 1999, the Company entered into a swap arrangement with a major financial
institution that effectively converts the interest rate on $16.4 million
notional amount of the 9 1/2 % Senior Subordinated Notes due 2008 ("Notes")
to a variable LIBOR-based rate. In February 2000, this arrangement was
extended through February 26, 2001. Based on LIBOR rates in effect at June
30, 2000, this amounted to a net reduction in the carrying cost of the Notes
from 9 1/2 % to 7.03%, or 247 basis points. In addition, the swap
arrangement also effectively sets the price at which the Company can
repurchase these Notes. For the three and six months ended June 30, 2000,
the Company recorded market adjustments of $410,000 and ($371,000),
respectively, related to the change in the fair value of the Notes. In July
2000, a portion of this swap arrangement was settled on a notional amount of
$5.0 million of the Notes. The Company will record a gain of approximately
$100,000 as a result of this settlement.
For 2000, the Company entered into swap contracts on 16,500 barrels of oil
per day ("BOPD"), at an average West Texas Intermediate ("WTI") price of
$17.94 per barrel. The Company also entered into collars on an additional
16,500 BOPD, with a floor of $16.00 per barrel and ceiling of $21.21 per
barrel. This production is hedged based on a fixed NYMEX price. In May 2000,
in connection with the sale of certain non-core California oil and gas
properties (see Note 9), the Company unwound the $21.21 per barrel ceiling on
2,800 BOPD for the period May 2000 through December 2000. Also for the year
2000, the Company has entered into basis swaps on 3,000 BOPD of its
production in the Congo, hedging the basis differential between No. 6 fuel
oil and WTI at an average differential of $1.88 per barrel. At June 30, 2000,
the market value of the hedge positions was a loss of approximately $50.1
million.
For 2001, the Company has entered into swap arrangements on 26,000 BOPD for
the first quarter at an average WTI price of $19.52 per barrel, for the
second quarter on 25,000 BOPD at an average WTI price of $19.54 per barrel,
for the third quarter on 20,000 BOPD at an average WTI price of $21.22 per
barrel, and for the fourth quarter on 15,500 BOPD at an average WTI price of
$22.95 per barrel. At June 30, 2000, the market value of these swaps was a
loss of $40.7 million. These agreements expose the Company to counterparty
credit risk to the extent that the counterparty is unable to meet its
settlement commitments to the Company.
CONTINGENCIES AND OTHER MATTERS
-------------------------------
The Company had been named as a defendant in Gloria Garcia Lopez and Husband,
Hector S. Lopez, Individually, and as successors to Galo Land & Cattle
Company v. Mobil Producing Texas & New Mexico, et al. in the 79th Judicial
District Court of Brooks County, Texas. On June 9, 2000, the parties entered
into a memorandum of settlement agreement, pursuant to which the lawsuit
would be dismissed (subject to and upon execution of final settlement
documents), the defendants would pay the plaintiffs $12.0 million and the
lease agreement would be amended. Nuevo's working interest in these
properties is 20%, and its share of the settlement payment is approximately
$2.4 million.
The Company has been named as a defendant in certain other lawsuits
incidental to its business. Management does not believe that the outcome of
such litigation will have a material adverse impact on the Company's
operating results or financial condition. However, these actions and claims
in the aggregate seek substantial damages against the Company and are subject
to the inherent uncertainties present in any litigation. The Company is
defending itself vigorously in all such matters.
17
<PAGE>
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
In March 1999, the Company discovered that a non-officer employee had
fraudulently authorized and diverted for personal use Company funds totaling
$5.9 million, $1.6 million in 1999 and the remainder in 1998, that were
intended for international exploration. The Board of Directors engaged a
Certified Fraud Examiner to conduct an in-depth review of the fraudulent
transactions. The investigation confirmed that only one employee was
involved in the matter and that all misappropriated funds were identified.
The Company has reviewed and, where appropriate, strengthened its internal
control procedures. As a result of ongoing negotiations, the Company is
confident that it will recoup a portion of the loss.
In September 1997, there was a spill of crude oil into the Santa Barbara
Channel from a pipeline that connects the Company's Point Pedernales field
with shore-based processing facilities. The volume of the spill was
estimated to be 163 barrels of oil. The costs of the clean up and the cost
to repair the pipeline either have been or are expected to be covered by
insurance, less the Company's deductibles, which in total are $120,000.
Repairs were completed by the end of 1997, and production recommenced in
December 1997. The Company also has exposure to costs that may not be
recoverable from insurance, including certain fines, penalties, and damages.
Such costs are not quantifiable at this time, but are not expected to be
material to the Company's operating results, financial condition or
liquidity.
The Company's international investments involve risks typically associated
with investments in emerging markets such as an uncertain political,
economic, legal and tax environment and expropriation and nationalization of
assets. In addition, if a dispute arises in its foreign operations, the
Company may be subject to the exclusive jurisdiction of foreign courts or may
not be successful in subjecting foreign persons to the jurisdiction of the
United States. The Company attempts to conduct its business and financial
affairs so as to protect against political and economic risks applicable to
operations in the various countries where it operates, but there can be no
assurance that the Company will be successful in so protecting itself. A
portion of the Company's investment in the Congo is insured through political
risk insurance provided by the Overseas Private Investment Corporation
("OPIC"). The Company will consider its options for political risk insurance
in Ghana as it evaluates business opportunities.
In connection with their respective acquisitions of two subsidiaries owning
interests in the Yombo field offshore West Africa (each a "Congo
subsidiary"), the Company and a wholly-owned subsidiary of CMS NOMECO Oil &
Gas Co. ("CMS") agreed with the seller not to claim certain tax losses
incurred by such subsidiaries prior to the acquisitions. Pursuant to the
agreement, the Company and CMS may be liable to the seller for the recapture
of these tax losses utilized by the seller in years prior to the acquisitions
if certain triggering events occur. A triggering event will not occur if a
subsequent purchaser enters into certain agreements specified in the
consolidated return regulations intended to ensure that such losses will not
be claimed. The Company's potential direct liability could be as much as
$48.5 million if a triggering event with respect to the Company occurs, and
the Company believes that CMS's liability (for which the Company would be
jointly liable with an indemnification right against CMS) could be as much as
$64.1 million. The Company does not expect a triggering event to occur with
respect to it or CMS and does not believe the agreement will have a material
adverse effect upon the Company.
Contingent Payment and Price Sharing Agreements
-----------------------------------------------
In connection with the acquisition from Unocal in 1996 of the properties
located in California, the Company is obligated to make a contingent payment
for the years 1998 through 2004 if oil prices exceed thresholds set forth in
the agreement with Unocal. The contingent payment will equal 50% of the
difference between the actual average annual price received on a field-by-
field basis (capped by a maximum price) and a minimum price, less ad valorem
and production taxes, multiplied by the actual number of barrels of oil sold
that are produced from the properties acquired from Unocal during the
respective year. The minimum price of $17.75 per Bbl. under the agreement
(determined based on near month of delivery of WTI crude oil on the NYMEX) is
escalated at 3% per year and the maximum price of $21.75 per Bbl. on the
NYMEX is escalated at 3% per year. Minimum and maximum prices are reduced to
reflect the field level price by subtracting a fixed differential established
for each field. The reduction was established at approximately the
differential between actual sales prices and NYMEX prices in effect in 1995
($4.34 per Bbl. weighted average for all the properties
18
<PAGE>
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
acquired from Unocal). The Company accumulates credits to offset the
contingent payment when prices are $.50 per Bbl. or more below the minimum
price. The Company computes this calculation annually and had accumulated
$30.8 million in price credits as of December 31, 1999, which will be used to
reduce future amounts owed under the contingent payment.
In connection with the acquisition of the Congo properties in 1995, the
Company entered into a price sharing agreement with the seller. Under the
terms of the agreement, if the average price received for the oil production
during the year is greater than the benchmark price established by the
agreement, then the Company is obligated to pay the seller 50% of the
difference between the benchmark price and the actual price received, for all
the barrels associated with this acquisition. The benchmark price for 2000 is
$15.19 per Bbl. The benchmark price increases each year based on the increase
in the Consumer Price Index. For 2000, the effect of this agreement is that
Nuevo is entitled to receive the pricing upside above $15.19 per Bbl. on
approximately 56% of its Congo production.
The Company acquired a 12% working interest in the Point Pedernales oil field
from Unocal in 1994 and the remainder of its interest in this field from
Torch Energy Advisors Inc. ("Torch") in 1996. The Company is entitled to all
revenue proceeds up to $9.00 per Bbl., with the excess over $9.00 per Bbl.,
if any, shared among the Company and the original owners from whom Torch
acquired its interest. For 2000, the effect of this agreement is that Nuevo
is entitled to receive the pricing upside above $9.00 per Bbl. on
approximately 34% of its net Point Pedernales production.
RECENT ACCOUNTING PRONOUNCEMENTS
--------------------------------
In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities".
This statement, as amended by SFAS No. 137 and SFAS No. 138, establishes
standards of accounting for and disclosures of derivative instruments and
hedging activities. This statement requires all derivative instruments to be
carried on the balance sheet at fair value and is effective for the Company
beginning January 1, 2001. The Company has not yet determined the impact of
this statement on its financial condition or results of operations.
19
<PAGE>
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
SHARE REPURCHASES
-----------------
In August 1999, the Company implemented a share repurchase program, pursuant
to the Board of Directors' authorizations to repurchase up to a total of
3,616,600 shares at times and at prices deemed attractive by management. As
of June 30, 2000, the Company has repurchased 2,660,600 shares of its common
stock in open market transactions at an average purchase price, including
commissions, of $16.79 per share.
DEFERRED INCOME TAXES
---------------------
The Company has deferred tax assets, net of valuation allowances, of $23.0
million and $24.0 million as of June 30, 2000 and December 31, 1999,
respectively. The Company believes that sufficient future taxable income will
be generated and has concluded that these net deferred tax assets will more
likely than not be realized.
RESULTS OF OPERATIONS (THREE MONTHS ENDED JUNE 30, 2000 AND 1999)
-----------------------------------------------------------------
The following table sets forth certain operating information of the Company
(inclusive of the effect of crude oil and natural gas hedging) for the
periods presented:
<TABLE>
<CAPTION>
Three Months
Ended June 30,
--------------- %
Increase/
2000 1999 (Decrease)
------ ------ ----------
<S> <C> <C> <C>
PRODUCTION:
Oil and condensate - Domestic (MBBL.S).................... 3,640 3,831 (5%)
Oil and condensate - International (MBBL.S)............... 477 459 4%
------ ------
Oil and condensate - Total (MBBL.S)....................... 4,117 4,290 (4%)
Natural gas - Domestic (MMCF)............................. 3,816 4,135 (8%)
Natural gas liquids - Domestic (MMCF)..................... 44 50 (12%)
Equivalent barrels of production - Domestic (MBOE)........ 4,320 4,570 (5%)
Equivalent barrels of production - International (MBOE)... 477 459 4%
------ ------
Equivalent barrels of production - Total (MBOE)........... 4,797 5,029 (5%)
AVERAGE SALES PRICE:
Oil and condensate - Domestic............................. $13.12 $ 9.50 38%
Oil and condensate - International........................ $22.63 $15.73 44%
Oil and condensate - Total................................ $14.23 $10.17 40%
Natural gas - Domestic.................................... $ 3.43 $ 1.92 79%
LEASE OPERATING EXPENSE:
Average unit production cost(1) per BOE - Domestic........ $ 7.12 $ 5.90 21%
Average unit production cost(1) per BOE - International... $ 7.37 $ 7.28 1%
Average unit production cost(1) per BOE - Total........... $ 7.14 $ 6.02 19%
</TABLE>
(1) Costs incurred to operate and maintain wells and related equipment and
facilities, including ad valorem and severance taxes.
20
<PAGE>
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Revenues
--------
Oil and Gas Revenues:
Oil and gas revenues for the three months ended June 30, 2000, were $72.6
million, or 37% higher than oil and gas revenues for the same period in 1999.
This increase is primarily due to a 40% increase in realized oil prices and a
79% increase in realized gas prices. These increases were partially offset by a
decrease in production, which was primarily attributable to asset sales,
production interruptions due to pump replacements and power shortages (brown-
outs) in California during recent periods of extreme temperatures, and reduced
capital spending in 1999. Second quarter 2000 oil price realizations reflect
hedging losses of $24.8 million, or $6.03 per barrel.
Domestic: Oil and gas revenues for the three months ended June 30, 2000, were
35% higher than oil and gas revenues for the same period in 1999. This increase
is primarily due to a 38% improvement in average realized oil prices and a 79%
improvement in average realized gas prices, partially offset by a 5% decrease in
total production. The Company experienced several production interruptions in
the second quarter of 2000 as a result of pump replacements and brown-outs in
California during recent periods of extreme temperatures. The realized oil
price of $13.12 per barrel for the second quarter of 2000 includes negative
hedging results of $7.01 per barrel of oil, compared to negative hedging results
of $2.51 per barrel of oil for the second quarter of 1999.
International: Oil revenues for the three months ended June 30, 2000, increased
49% as compared to the same period in 1999. This increase resulted from a 44%
increase in oil price realizations to $22.63 per barrel, coupled with a 4%
increase in oil production. The realized oil price for the second quarter of
2000 includes hedging gains of $1.44 per barrel of oil, compared to hedging
gains of $1.39 per barrel in the second quarter of 1999.
Gain on Sale of Assets, net:
The net gain on sale of assets for the three months ended June 30, 2000, was
$366,000, primarily representing a gain on the sale of certain non-core
California properties (see Note 9 to the Notes to Condensed Consolidated
Financial Statements). Gain on sale of assets, net, for the three months ended
June 30, 1999, was $(1.4) million, representing a negative revision for final
accounting adjustments in connection with the Company's sale of its East Texas
natural gas properties in January 1999.
Interest and Other Income:
Interest and other income for the three months ended June 30, 2000, is comprised
of several individually insignificant items. Interest and other income for the
three months ended June 30, 1999, includes $1.1 million associated with interest
earned on an escrow account for the $100.0 million representing a portion of the
proceeds from the sale of the East Texas natural gas properties, as well as
several individually insignificant items.
Expenses
--------
Lease Operating Expenses:
Lease operating expenses for the three months ended June 30, 2000, were $34.3
million, or 13% higher than for the three months ended June 30, 1999. Lease
operating expenses per barrel of oil equivalent ("BOE") were $7.14 in the second
quarter of 2000, compared to $6.02 in the same period in 1999. The increase is
primarily due to a $4.3 million increase in steam costs resulting from higher
natural gas prices, as well as lower production.
Domestic: Lease operating expenses per BOE were $7.12 in the second quarter of
2000, compared to $5.90 in the same period in 1999. Higher steam costs and
decreased production contributed to the higher lease operating expenses per BOE
quarter over quarter.
21
<PAGE>
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Exploration Costs:
Exploration costs, including geological and geophysical ("G&G") costs, dry hole
costs, delay rentals and expensed project costs, were $1.5 million and $7.9
million for the three months ended June 30, 2000 and 1999, respectively. For the
three months ended June 30, 2000, exploration costs were comprised of $0.6
million in G&G (primarily for consulting costs and 3-D seismic processing in the
Accra-Keta prospect offshore Ghana), $0.1 million in dry hole costs, $0.2
million in delay rentals, and $0.6 million of other project costs. For the
three months ended June 30, 1999, exploration costs were comprised of $6.5
million of dry hole costs (for the Cree Fee 1A well on the Midway Peak prospect
in California), $0.7 million in G&G, $0.1 million in delay rentals and $0.6
million of other project costs.
Depreciation, Depletion and Amortization:
Depreciation, depletion and amortization for the three months ended June 30,
2000, reflects a 32% decrease from the same period in 1999. This decrease was
driven by a lower depletion rate, which primarily resulted from a significant
increase in reserve estimates attributable to higher commodity prices at year-
end 1999 versus year-end 1998.
General and Administrative Expenses:
General and administrative expenses were $4.1 million and $3.4 million in the
three months ended June 30, 2000 and 1999, respectively. The 22% increase is
due primarily to a $0.9 million increase in bonus accruals, as bonuses were not
projected or accrued in the second quarter of 1999, offset by a $0.4 million
decrease in the fair market value of securities in the Company's deferred
compensation plan. The remaining increase is made up of individually
insignificant items.
Other Expense:
The $2.2 million increase in other expense from the second quarter of 1999 to
the second quarter of 2000 is primarily due to a $2.0 million accrual for a
lawsuit settlement (see Note 7 to the Notes to Condensed Consolidated Financial
Statements) and $0.7 million in costs to evaluate potential business
transactions. This increase was partially offset by a positive mark to market
adjustment of $0.4 million related to the Company's liability management swap
(see Note 1 to the Notes to Condensed Consolidated Financial Statements) in the
second quarter of 2000.
Net Income (Loss)
-----------------
Net income of $854,000, $0.05 per common share - basic and diluted, was reported
for the three months ended June 30, 2000, as compared to a net loss of $15.6
million, $0.78 per common share - basic and diluted, reported for the same
period in 1999.
22
<PAGE>
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
RESULTS OF OPERATIONS (SIX MONTHS ENDED JUNE 30, 2000 AND 1999)
---------------------------------------------------------------
The following table sets forth certain operating information of the Company
(inclusive of the effect of crude oil and natural gas hedging) for the periods
presented:
<TABLE>
<CAPTION>
Six Months
Ended June 30,
------------------ %
Increase/
2000 1999 (Decrease)
------ ------- ---------
<S> <C> <C> <C>
PRODUCTION:
Oil and condensate - Domestic (MBBL.S).................... 7,353 7,815 (6%)
Oil and condensate - International (MBBL.S)............... 978 849 15%
------ -------
Oil and condensate - Total (MBBL.S)....................... 8,331 8,664 (4%)
Natural gas - Domestic (MMCF)............................. 7,811 8,227 (5%)
Natural gas liquids - Domestic (MMCF)..................... 85 93 (9%)
Equivalent barrels of production - Domestic (MBOE)........ 8,741 9,279 (6%)
Equivalent barrels of production - International (MBOE)... 978 849 15%
------ -------
Equivalent barrels of production - Total (MBOE)........... 9,719 10,128 (4%)
AVERAGE SALES PRICE:
Oil and condensate - Domestic............................. $13.13 $ 7.29 80%
Oil and condensate - International........................ $22.47 $ 12.86 75%
Oil and condensate - Total................................ $14.22 $ 9.07 57%
Natural gas - Domestic.................................... $ 2.91 $ 1.87 56%
LEASE OPERATING EXPENSE:
Average unit production cost(1) per BOE - Domestic........ $ 6.69 $ 5.81 15%
Average unit production cost(1) per BOE - International... $ 7.02 $ 7.44 (6%)
Average unit production cost(1) per BOE - Total........... $ 6.73 $ 5.95 13%
</TABLE>
(1) Costs incurred to operate and maintain wells and related equipment and
facilities, including ad valorem and severance taxes.
Revenues
--------
Oil and Gas Revenues:
Oil and gas revenues for the six months ended June 30, 2000, were $143.3
million, or 49% higher than oil and gas revenues for the same period in 1999.
This increase is primarily due to a 57% increase in realized oil prices and a
56% increase in realized gas prices. These increases were partially offset by a
decrease in production, which was primarily attributable to asset sales,
production interruptions due to pump replacements and brown-outs in California
during recent periods of extreme temperatures, and reduced capital spending in
1999. First half 2000 oil price realizations reflect hedging losses of $51.3
million, or $6.16 per barrel, compared to hedging losses of $8.8 million, or
$1.01 per barrel in the first half of 1999.
Domestic: Oil and gas revenues for the six months ended June 30, 2000, were 42%
higher than oil and gas revenues for the same period in 1999. This increase is
primarily due to an 80% improvement in average realized oil prices and a 56%
improvement in average realized gas prices, partially offset by a 6% decrease in
total production as a result of asset sales, reduced capital spending in 1999
and production interruptions due to pump replacements and brown-outs
23
<PAGE>
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
in California during recent periods of extreme temperatures. The realized oil
price of $13.13 per barrel for the first half of 2000 includes negative hedging
results of $53.4 million, or $7.26 per barrel of oil, compared to hedging losses
of $9.6 million, or $1.23 per barrel in the first half of 1999.
International: Oil revenues for the six months ended June 30, 2000, more than
doubled as compared to the same period in 1999. This significant increase
resulted from a 75% increase in oil price realizations to $22.47 per barrel,
coupled with a 15% increase in oil production. The realized oil price for the
first half of 2000 includes hedging gains of $2.08 per barrel of oil, compared
to hedging gains of $0.98 per barrel in the first half of 1999.
Gain on Sale of Assets, net:
Gain on sale of assets for the six months ended June 30, 2000, was $506,000,
primarily representing a gain on the sale of certain non-core California
properties (see Note 9 to the Notes to Condensed Consolidated Financial
Statements). Gain on sale of assets for the six months ended June 30, 1999, was
$80.3 million, resulting from the Company's sale of its East Texas natural gas
properties in January 1999.
Interest and Other Income:
Interest and other income for the six months ended June 30, 2000, is comprised
of several individually insignificant items. Interest and other income for the
six months ended June 30, 1999, includes $2.4 million associated with interest
earned on an escrow account for the $100.0 million representing a portion of the
proceeds from the sale of the East Texas natural gas properties, as well as
several individually insignificant items.
Expenses
--------
Lease Operating Expenses:
Lease operating expenses for the six months ended June 30, 2000, were $65.4
million, or 9% higher than for the six months ended June 30, 1999. This
increase is primarily due to a $7.0 million increase in steam costs resulting
from higher natural gas prices, partially offset by a decrease in other field
costs. Lease operating expenses per BOE were $6.73 in the first half of 2000,
compared to $5.95 in the same period in 1999. The per barrel increase is
primarily due to a $0.66 per BOE increase in steam costs, as well as the 4%
decrease in total production.
Domestic: Lease operating expenses per BOE were $6.69 in the first half of 2000,
compared to $5.81 in the same period in 1999. Higher steam costs accounted for
$0.85 of the per BOE increase, year over year. The remaining increase is
attributable to the 4% decrease in production.
International: Lease operating expenses per BOE were $7.02 in the first half of
2000, compared to $7.44 in the same period in 1999. The decrease in lease
operating expenses per BOE is primarily attributable to the 15% increase in
production.
Exploration Costs:
Exploration costs, including G&G costs, dry hole costs, delay rentals and
expensed project costs, were $4.7 million and $10.0 million for the six months
ended June 30, 2000 and 1999, respectively. For the six months ended June 30,
2000, exploration costs were comprised of $3.8 million in G&G (primarily for 3-D
seismic acquisition and processing in the Accra-Keta prospect offshore Ghana),
$0.1 million in dry hole costs, $0.2 million in delay rentals, and $0.6 million
of other project costs. For the six months ended June 30, 1999, exploration
costs were comprised of $7.3 million of dry hole costs (for the Cree Fee 1A well
on the Midway Peak prospect in California), $1.5 million in G&G, $0.3 million in
delay rentals and $0.9 million of other project costs.
24
<PAGE>
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Depreciation, Depletion and Amortization:
Depreciation, depletion and amortization for the six months ended June 30, 2000,
reflects a 31% decrease from the same period in 1999. This decrease was driven
by a lower depletion rate, which primarily resulted from a significant increase
in reserve estimates attributable to higher commodity prices at year-end 1999
versus year-end 1998.
General and Administrative Expenses:
General and administrative expenses were $9.5 million and $7.2 million for the
six months ended June 30, 2000 and 1999, respectively. The 32% increase is due
primarily to a $1.6 million increase in bonus accruals, as bonuses were not
projected or accrued in the first half of 1999. The remaining increase is made
up of individually insignificant items.
Interest Expense:
Interest expense of $16.8 million for the six months ended June 30, 2000,
increased only slightly as compared to interest expense in the same period in
1999. The increase is primarily attributable to higher interest rates as the
Company exchanged its 8 7/8% Senior Subordinated Notes for 9 1/2% Senior
Subordinated Notes due 2008 in the third quarter of 1999.
Other Expense:
The 29% increase in other expense from the first half of 1999 to the first half
of 2000 is primarily due to a $2.0 million accrual for a lawsuit settlement (see
Note 7 to the Notes to Condensed Consolidated Financial Statements) and $0.7
million in costs to evaluate potential business transactions. This increase also
includes a negative mark to market adjustment of $0.4 million related to the
Company's liability management swap (see Note 1 to the Notes to Condensed
Consolidated Financial Statements) in the first half of 2000. Offsetting this
increase, in March 1999, the Company discovered that a non-officer employee had
fraudulently authorized and diverted for personal use Company funds totaling
$5.9 million, $4.3 million in 1998 and the remainder in the first quarter of
1999, that were intended for international exploration.
Net Income
----------
Net income of $1.5 million, $0.08 per common share - basic and diluted, was
reported for the six months ended June 30, 2000, as compared to net income of
$15.8 million, $0.80 per common share - basic and $0.79 per common share -
diluted, reported for the same period in 1999.
25
<PAGE>
NUEVO ENERGY COMPANY
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information contained in Item 3 updates, and should be read in conjunction
with, information set forth in Part II, Item 7a in Nuevo's Annual Report on Form
10-K for the year ended December 31, 1999, in addition to the interim condensed
consolidated financial statements and accompanying notes presented in Items 1
and 2 of this Form 10-Q.
There are no material changes in market risks faced by the Company from those
reported in Nuevo's Annual Report on Form 10-K for the year ended December 31,
1999.
26
<PAGE>
NUEVO ENERGY COMPANY
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
------- -----------------
See Note 7 to the Notes to Condensed Consolidated Financial Statements.
On April 5, 2000, the Company filed a lawsuit against ExxonMobil
Corporation in the United States District Court for the Central
District of California, Western Division. The Company and ExxonMobil
each own a 50% interest in the Sacate Field, offshore Santa Barbara
County, California. The Company has alleged that by grossly inflating
the fee that ExxonMobil insists the Company must pay to use an existing
ExxonMobil platform and production infrastructure, ExxonMobil failed to
submit a proposal for the development of the Sacate field consistent
with the Unit Operating Agreement. The Company therefore believes that
it has been denied a reasonable opportunity to exercise its rights
under the Unit Operating Agreement. The Company has alleged that
ExxonMobil's actions breach the Unit Operating Agreement and the
covenant of good faith and fair dealing. The Company is seeking damages
and a declaratory judgment as to the payment that must be made to
access ExxonMobil's platform and facilities.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
------- ---------------------------------------------------
At the annual meeting of the stockholders of the Company on May 24,
2000 the following matters were voted on with the following results:
(1) Isaac Arnold, Jr. was elected as a director of the Company with a
total of 14,443,384 shares voting in favor and 492,778 shares
withheld authority.
(2) Thomas D. Barrow was elected as a director of the Company with a
total of 14,923,896 shares voting in favor and 12,266 shares
withheld authority.
(3) David H. Batchelder was elected as a director of the Company with
a total of 14,924,625 shares voting in favor and 11,537 shares
withheld authority.
(4) Charles M. Elson was elected as a director of the Company with a
total of 14,923,743 shares voting in favor and 12,419 shares
withheld authority.
(5) Douglas L. Foshee was elected as a director of the Company with a
total of 14,923,941 shares voting in favor and 12,221 shares
withheld authority.
(6) Robert L. Gerry, III was elected as a director of the Company with
a total of 14,924,139 shares voting in favor and 12,023 shares
withheld authority.
(7) Gary R. Petersen was elected as a director of the Company with a
total of 14,924,139 shares voting in favor and 12,023 shares
withheld authority.
(8) David Ross, III was elected as a director of the Company with a
total of 14,924,625 shares voting in favor and 11,537 shares
withheld authority.
(9) Robert W. Shower was elected as a director of the Company with a
total of 14,924,625 shares voting in favor and 11,537 shares
withheld authority.
(10) The stockholders approved a proposal to ratify the selection of
KPMG LLP as the Company's independent auditors for the year ending
December 31, 2000, with a total of 14,914,285 shares voting in
favor, a total of 5,121 shares voting against and a total of
16,756 shares abstaining.
27
<PAGE>
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
------ --------------------------------
(A) EXHIBITS
10. Material Contracts
10.1 Third Restated Credit Agreement dated June 7, 2000, between
Nuevo Energy Company (Borrower) and Bank of America N.A.
(Administrative Agent), Bank One, NA (Syndication Agent),
Bank of Montreal (Documentation Agent) and certain lenders.
27. Financial Data Schedule
28
<PAGE>
NUEVO ENERGY COMPANY
PART II. OTHER INFORMATION (CONTINUED)
SIGNATURES
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, thereunto duly authorized.
NUEVO ENERGY COMPANY
(Registrant)
Date: August 14, 2000 By:/s/ Douglas L. Foshee
--------------- ----------------------------
Douglas L. Foshee
Chairman, President and Chief Executive
Officer
Date: August 14, 2000 By:/s/ Robert M. King
--------------- ------------------------------
Robert M. King
Senior Vice President and Chief
Financial Officer
29
