<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 September 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 November 9, 2000, the number of outstanding shares of the Registrant's
common stock was 17,611,729.
<PAGE>
NUEVO ENERGY COMPANY
INDEX
<TABLE>
<CAPTION>
PAGE
NUMBER
<S> <C>
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
Condensed Consolidated Balance Sheets:
September 30, 2000 (Unaudited) and December 31, 1999........................................ 3
Condensed Consolidated Statements of Operations (Unaudited):
Three and nine months ended September 30, 2000 and September 30, 1999....................... 4
Condensed Consolidated Statements of Cash Flows (Unaudited):
Nine months ended September 30, 2000 and September 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........................................ 27
PART II. OTHER INFORMATION................................................................................ 28
</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>
September 30, 2000 December 31, 1999
------------------ -----------------
<S> <C> <C>
ASSETS (Unaudited)
------
CURRENT ASSETS:
Cash and cash equivalents.......................................... $ 51,275 $ 10,288
Accounts receivable................................................ 55,775 45,004
Product inventory.................................................. 602 4,610
Prepaid expenses and other......................................... 3,618 6,389
--------------- ---------------
Total current assets............................................. 111,270 66,291
--------------- ---------------
PROPERTY AND EQUIPMENT, at cost:
Land............................................................... 51,017 51,017
Oil and gas properties (successful efforts method)................. 1,076,269 1,002,779
Gas plant facilities............................................... 12,020 12,140
Other facilities................................................... 14,259 11,874
--------------- ---------------
1,153,565 1,077,810
Accumulated depreciation, depletion and amortization............... (478,949) (429,349)
--------------- ---------------
674,616 648,461
--------------- ---------------
DEFERRED TAX ASSETS, net............................................ 17,882 24,005
OTHER ASSETS........................................................ 27,152 21,273
--------------- ---------------
$ 830,920 $ 760,030
=============== ===============
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
CURRENT LIABILITIES:
Accounts payable ................................................ $ 22,176 $ 20,492
Accrued interest................................................. 8,410 2,353
Accrued liabilities.............................................. 34,132 37,755
Current maturities of long-term debt............................. --- 750
--------------- ---------------
Total current liabilities..................................... 64,718 61,350
--------------- ---------------
LONG-TERM DEBT, net of current maturities........................... 409,727 340,750
OTHER LONG-TERM LIABILITIES......................................... 8,424 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,
17,599,672 and 18,007,297 shares issued and outstanding at
September 30, 2000 and December 31, 1999, respectively......... 206 204
Additional paid-in capital....................................... 360,747 357,855
Treasury stock, at cost, 2,999,650 and 2,430,074 shares, at
September 30, 2000 and December 31, 1999, respectively......... (61,818) (49,605)
Stock held by benefit trust, 167,828 and 75,904 shares, at
September 30, 2000 and December 31, 1999, respectively......... (3,512) (3,184)
Deferred stock compensation...................................... (191) (216)
Accumulated deficit.............................................. (62,381) (71,416)
--------------- ---------------
Total stockholders' equity..................................... 233,051 233,638
--------------- ---------------
$ 830,920 $ 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)
<TABLE>
<CAPTION>
Three Months Ended September 30,
--------------------------------
2000 1999
---------- ----------
<S> <C> <C>
REVENUES:
Oil and gas revenues........................................... $ 87,328 $ 68,987
Gain on sale of assets, net.................................... --- (309)
Interest and other income...................................... 2,264 1,570
--------- ---------
89,592 70,248
--------- ---------
COSTS AND EXPENSES:
Lease operating expenses....................................... 38,226 35,629
Exploration costs.............................................. 791 620
Depreciation, depletion and amortization....................... 18,062 17,299
Loss on sale of assets, net.................................... 520 ---
General and administrative expenses............................ 3,918 4,636
Outsourcing fees............................................... 3,436 3,603
Interest expense............................................... 9,789 7,948
Dividends on Guaranteed Preferred
Beneficial Interests in Company's
Convertible Debentures (TECONS)............................. 1,653 1,653
Other expense.................................................. 572 3,454
--------- ---------
76,967 74,842
--------- ---------
Income (loss) before income taxes................................. 12,625 (4,594)
Provision (benefit) for income taxes.............................. 5,089 (1,838)
--------- ---------
NET INCOME (LOSS)................................................. $ 7,536 $ (2,756)
========= =========
EARNINGS (LOSS) PER SHARE:
Basic:
Earnings (loss) per common share.................................. $ 0.43 $ (0.14)
========= =========
Weighted average common shares outstanding........................ 17,589 19,610
========= =========
Diluted:
Earnings (loss) per common share.................................. $ 0.42 $ (0.14)
========= =========
Weighted average common and dilutive potential
common shares outstanding......................................... 17,886 19,610
========= =========
</TABLE>
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)
<TABLE>
<CAPTION>
Nine Months Ended September 30,
-------------------------------
2000 1999
---------- ----------
<S> <C> <C>
REVENUES:
Oil and gas revenues........................................... $ 230,656 $ 165,327
Gain on sale of assets, net.................................... --- 80,003
Interest and other income...................................... 3,085 4,421
--------- ----------
233,741 249,751
--------- ----------
COSTS AND EXPENSES:
Lease operating expenses....................................... 103,610 95,841
Exploration costs.............................................. 5,533 10,619
Depreciation, depletion and amortization....................... 49,885 63,556
Loss on sale of assets, net.................................... 14 ---
General and administrative expenses............................ 13,391 11,835
Outsourcing fees............................................... 10,199 10,449
Interest expense............................................... 26,596 24,348
Dividends on Guaranteed Preferred
Beneficial Interests in Company's
Convertible Debentures (TECONS)............................. 4,959 4,959
Other expense.................................................. 4,419 6,433
--------- ----------
218,606 228,040
--------- ----------
Income before income taxes........................................ 15,135 21,711
Provision for income taxes........................................ 6,100 8,683
--------- ----------
NET INCOME........................................................ $ 9,035 $ 13,028
========= ==========
EARNINGS PER SHARE:
Basic:
Earnings per common share......................................... $ 0.51 $ 0.66
========= ==========
Weighted average common shares outstanding........................ 17,663 19,768
========= ==========
Diluted:
Earnings per common share......................................... $ 0.50 $ 0.65
========= ==========
Weighted average common and dilutive potential
common shares outstanding......................................... 18,013 19,902
========= ==========
</TABLE>
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>
Nine Months Ended September 30,
--------------------------------
2000 1999
------ -------
<S> <C> <C>
Cash flows from operating activities:
Net income...................................................... $ 9,035 $ 13,028
Adjustments to reconcile net income to
net cash provided by/(used in) operating activities:
Depreciation, depletion and amortization.............. 49,885 63,556
Loss (gain) on sale of assets, net.................... 14 (80,003)
Dry hole costs........................................ 91 7,324
Amortization of other costs........................... 1,396 1,254
Debt modification costs............................... -- 2,883
Deferred taxes........................................ 6,471 7,183
Mark to market of deferred compensation plan.......... (53) 577
Other................................................. 108 120
--------- ---------
66,947 15,922
Changes in assets and liabilities:
Accounts receivable....................................... (10,771) (13,234)
Accounts payable and accrued liabilities.................. 4,118 (7,174)
Other..................................................... 3,650 2,127
--------- ---------
Net cash provided by/(used in) operating activities............ 63,944 (2,359)
--------- ---------
Cash flows from investing activities:
Additions to oil and gas properties....................... (76,216) (41,849)
Acquisitions of oil and gas properties.................... -- (61,416)
Additions to gas plant facilities......................... (126) (3,420)
Additions to other facilities............................. (2,384) (8,938)
Proceeds from sales of properties......................... 2,584 199,663
--------- ---------
Net cash (used in)/provided by investing activities............. (76,142) 84,040
--------- ---------
Cash flows from financing activities:
Proceeds from borrowings.................................. 197,100 134,590
Payments of long-term debt................................ (128,873) (195,267)
Deferred financing and modification costs................. (4,964) (7,872)
Treasury stock purchases.................................. (12,540) (19,802)
Proceeds from issuance of common stock.................... 2,462 1,454
--------- ---------
Net cash provided by/(used in) financing activities............. 53,185 (86,897)
--------- ---------
Net increase (decrease) in cash and cash equivalents...... 40,987 (5,216)
Cash and cash equivalents at beginning of period.......... 10,288 7,403
--------- ---------
Cash and cash equivalents at end of period...................... $ 51,275 $ 2,187
========= =========
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amounts capitalized)..................... $ 19,143 $ 23,133
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 September 30, 2000 and December 31, 1999 and the results of operations and
changes in cash flows for the periods ended September 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").
The SEC is currently reviewing certain of the Company's historical financial
statements, reserve information and other information included in the
Company's periodic filings, in conjunction with the Company's filing of a
shelf registration statement on Form S-3. In the course of the review by the
SEC of the registration statement, the Company may be required to make
changes to the description of its business, reserves, financial
statements and other information. While the Company believes that its
historical financial statements have been prepared in a manner that complies,
in all material respects, with generally accepted accounting principles and
the regulations published by the SEC, and that its reserve and other
disclosures are in accordance with applicable SEC guidelines, comments by the
SEC on the registration statement may require modification or reformulation
of the Company's financial statements and other information previously filed
with the SEC.
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 decreases 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 September 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
$32.6 million and $16.5 million in the third quarter of 2000 and 1999,
respectively. For the first nine months of 2000 and 1999, oil and gas
revenues were reduced by $83.9 million and $25.3 million, respectively, as a
result of hedging transactions.
In 1999, the Company entered into a swap arrangement with a major financial
institution that effectively converted 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 addition, the swap arrangement effectively
set the price at which
7
<PAGE>
Nuevo Energy Company
--------------------
Notes to Condensed Consolidated Financial Statements (Continued)
----------------------------------------------------------------
(Unaudited)
the Company could repurchase these Notes. In the third quarter of 2000, this
swap arrangement was settled, resulting in no significant impact to the
Company's results of operations.
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 cost-less 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 September 30,
2000, the market value of these hedge positions was a loss of approximately
$28.1 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 September 30, 2000, the market value of these swaps was
a loss of $64.0 million.
For 2002, the Company has entered into swap arrangements on 12,500 BOPD for
the first quarter at an average WTI price of $25.91 per barrel. For the
remainder of 2002, the Company purchased put options with a strike price of
$22.00 per barrel WTI, on 19,000 BOPD for the second quarter, and on 14,000
BOPD for both the third and fourth quarters. At September 30, 2000, the
market value of these hedge positions is a gain of $0.3 million. All of 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 that changes in the derivative's fair
value be recognized currently in earnings unless specific hedge accounting
criteria are met. Accounting for qualifying hedges allows derivative gains
and losses to be reported in other comprehensive income until the hedged
transaction occurs, and requires formal documentation and assessment of the
effectiveness of transactions that receive hedge accounting.
The Company must adopt SFAS No. 133 by January 1, 2001, and does not plan to
adopt early. On adoption, the provisions of this statement must be applied
prospectively. The Company has completed an inventory of all known
derivatives and is in the process of documenting the relevant hedge
relationships. The Company expects that the adoption of SFAS No. 133 will
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. Although the Company currently
believes that its derivative financial instruments will qualify for hedge
accounting under SFAS No. 133, the Company has not yet determined the impact
of the implementation 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
8
<PAGE>
Nuevo Energy Company
--------------------
Notes to Condensed Consolidated Financial Statements (Continued)
---------------------------------------------------------------
(Unaudited)
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 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 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 had deferred tax assets, net of valuation allowances, of $17.9
million and $24.0 million as of September 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 September 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 Republics of Congo and Ghana in West Africa.
<TABLE>
<CAPTION>
For the Nine Months Ended September 30,
---------------------------------------
2000 1999
------------ ------------
(amounts in thousands)
<S> <C> <C>
Sales to unaffiliated customers:
Oil and gas - Domestic.................... $199,550 $144,583
Oil and gas - International............... 31,106 20,744
-------- --------
Total sales................................ 230,656 165,327
Gain on sale of assets, net............... --- 80,003
Other revenues............................ 3,085 4,421
-------- --------
Total revenues............................. $233,741 $249,751
======== ========
Operating profit before income taxes:
Oil and gas - Domestic (a)................ $ 62,116 $ 72,539
Oil and gas - International............... 10,597 3,568
-------- --------
72,713 76,107
Unallocated corporate expenses............. 26,023 25,089
Interest expense........................... 26,596 24,348
Dividends on TECONS........................ 4,959 4,959
-------- --------
Income before income taxes................ $ 15,135 $ 21,711
======== ========
Depreciation, depletion and amortization:
Oil and gas - Domestic.................... $ 42,418 $ 56,212
Oil and gas - International............... 6,368 6,174
Other..................................... 1,099 1,170
-------- --------
$ 49,885 $ 63,556
======== ========
</TABLE>
(a) Includes an $80.3 million gain on sale of the East Texas gas properties
for the nine months ended September 30, 1999.
5. Long-Term Debt
--------------
Long-term debt consists of the following (amounts in thousands):
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
------------------ -----------------
<S> <C> <C>
9 3/8% Senior Subordinated Notes due 2010 (a).................... $150,000 $ ---
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 (b)......................................... --- 81,000
OPIC credit facility............................................. --- 750
------------------ -----------------
Total debt............................................... 409,727 341,500
Less: current maturities......................................... --- (750)
------------------ -----------------
Long-term debt................................................... $409,727 $340,750
================== =================
</TABLE>
(a) In September 2000, the Company issued $150.0 million of 9 3/8% Senior
Subordinated Notes due October 1, 2010 ("9 3/8% Notes"). Interest on
the 9 3/8% Notes accrues at the rate of 9 3/8% per annum
10
<PAGE>
Nuevo Energy Company
--------------------
Notes to Condensed Consolidated Financial Statements (Continued)
---------------------------------------------------------------
(Unaudited)
and is payable semi-annually in arrears on April 1 and October 1. Net
proceeds from this offering of $146.6 million were used to repay
outstanding borrowings under the Company's credit facility and for
operating expenses and other general corporate purposes.
(b) 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, 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 September 30, 2000, was
$225.0 million, which is $75.0 million less than the previous
borrowing base due to the net effect of the Company's higher asset
valuation as of June 30, 2000, and its higher fixed interest costs
associated with the issuance of the 9 3/8% Notes. The Company was in
compliance with all covenants as of September 30, 2000, and does not
anticipate any issues of non-compliance arising in the foreseeable
future. At September 30, 2000, there were no outstanding borrowings
under the revolving credit agreement. Accordingly, $225.0 million of
credit capacity was unused and available at September 30, 2000.
6. Earnings (Loss) per Share Computation
-------------------------------------
SFAS No.128 requires a reconciliation of the numerator (income or loss) and
denominator (shares) of the basic earnings (loss) per share ("EPS")
computation to the numerator and denominator of the diluted EPS
computation. In the three-month period ended September 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 September 30,
-----------------------------------------------------------
2000 1999
------------------------------ ---------------------------
Income Shares Loss Shares
--------------- ------------- ------------ ------------
<S> <C> <C> <C> <C>
Earnings (loss) per Common share - Basic................. $7,536 17,589 $(2,756) 19,610
Effect of dilutive securities:
Stock options............................................ --- 297 --- ---
------ ------ ------- ------
Earnings (loss) per Common share - Diluted............... $7,536 17,886 $(2,756) 19,610
====== ====== ======= ======
For the Nine Months Ended September 30,
-----------------------------------------------------------
2000 1999
------------------------------ ---------------------------
Income Shares Income Shares
--------------- ------------- ------------ ------------
Earnings per Common share - Basic........................ $9,035 17,663 $13,028 19,768
Effect of dilutive securities:
Stock options............................................ --- 350 --- 134
------ ------ ------- ------
Earnings per Common share - Diluted...................... $9,035 18,013 $13,028 19,902
====== ====== ======= ======
</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 was dismissed, the defendants paid the plaintiffs $12.0
million and the lease agreement was amended. Nuevo's working interest in
these properties is 20%, and its share of the settlement payment was
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
11
<PAGE>
Nuevo Energy Company
--------------------
Notes to Condensed Consolidated Financial Statements (Continued)
----------------------------------------------------------------
(Unaudited)
-----------
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, where appropriate, strengthened its internal control
procedures. In August 2000, the Company recorded $1.5 million of other income
for a partial reimbursement of these previously expensed funds, resulting
from the negotiated settlement of a related legal claim.
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
$48.0 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
$64.6 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
12
<PAGE>
Nuevo Energy Company
--------------------
Notes to Condensed Consolidated Financial Statements (Continued)
----------------------------------------------------------------
(Unaudited)
-----------
per Bbl., under the agreement (determined based on the near month 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.
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 28% of the gross Point Pedernales production, or 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). Also, the Company sold certain of
its non-core assets during the third quarter of 2000, recognizing a net
loss of approximately $500,000.
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 September 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.
11. Legal Proceedings
-----------------
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.
13
<PAGE>
NUEVO ENERGY COMPANY
--------------------
Item2. 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"),
Section 21E of the Securities Exchange Act of 1934 ("Exchange Act"), and the
Private Securities Litigation Act of 1995. 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.
SEC REVIEW
----------
The SEC is currently reviewing certain of the Company's historical financial
statements, reserve information and other information included in the
Company's periodic filings, in conjunction with the Company's filing of a
shelf registration statement on Form S-3. In the course of the review by the
SEC of the registration statement, the Company may be required to make
changes to the description of its business, reserves, financial
statements and other information. While the Company believes that its
historical financial statements have been prepared in a manner that complies,
in all material respects, with generally accepted accounting principles and
the regulations published by the SEC, and that its reserve and other
disclosures are in accordance with applicable SEC guidelines, comments by the
SEC on the registration statement may require modification or reformulation
of the Company's financial statements and other information previously filed
with the SEC.
Capital Resources and Liquidity
-------------------------------
Since its 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 $63.9 million and $(2.4)
million for the nine months ended September 30, 2000 and 1999, respectively.
The Company invested $76.2 million and $103.3 million in oil and gas
properties for the nine months ended September 30, 2000 and 1999,
respectively.
The current borrowing base on the Company's credit facility is $225.0
million. At September 30, 2000, there were no outstanding borrowings under
the revolving credit agreement. Accordingly, $225.0 million of credit
capacity was unused and available at September 30, 2000. At September 30,
2000, the Company had working capital of $46.6 million.
On September 26, 2000, the Company issued $150.0 million of 9 3/8% Senior
Subordinated Notes due October 1, 2010 ("9 3/8% Notes"). Net proceeds from
this offering of $146.6 million were used to repay outstanding borrowings
under the Company's credit facility and for operating expenses and other
general corporate purposes.
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 September 30, 2000, was $225.0 million, which is $75.0
million less than the previous borrowing base due to the net effect of the
Company's higher asset valuation as of June 30, 2000, and its higher fixed
interest costs associated with the recently issued 9 3/8% Notes. The Company
was in compliance with all covenants as of September 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
14
<PAGE>
NUEVO ENERGY COMPANY
--------------------
Management's Discussion and Analysis of Financial
-------------------------------------------------
Condition and Results of Operations (Continued)
-----------------------------------------------
planned to sell or joint venture this property upon completion of the
entitlement process. This delay resulted from a political initiative that, if
passed, would have subjected certain future development projects, such as
Brea Highlands, to a public vote. The initiative was defeated in the November
7, 2000 election. Nevertheless, due to divisiveness within the City of Brea
over the issue of hillside development, the Company removed its entitlement
application from the City of Brea and submitted an entitlement application
with Orange County under the project name "Tonner Hills". 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.
Capital Expenditures
--------------------
As mentioned above, the Company decided to defer $20.0 million of its
original $140.0 million 2000 capital budget, as a result of expected delays
in the potential sale or joint venture of its Brea Highlands real estate
development. Under the revised 2000 capital budget of $120.0 million, the
Company anticipates spending approximately $37.0 million on development
activities, 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 nine months of 2000 and 1999 are
as follows (amounts in thousands):
<TABLE>
<CAPTION>
For the Nine Months Ended
September 30,
-----------------------------------------------
2000 1999
-------------------- --------------------
<S> <C> <C>
Domestic $75,726 $25,622
International 7,536 22,148
-------------------- --------------------
Total $83,262 $47,770
==================== ====================
</TABLE>
The following is a description of significant exploration and development
activity during the first nine months of 2000.
Exploration Activity
Domestic
--------
During 2000, the Company drilled a successful exploratory well on its Star
Fee lease in the Cymric Field in California, which was acquired from Texaco
in 1999. The Star Fee 701 deep well tested at a rate of over 900 barrels of
oil per day ("BOPD") and 1.2 million cubic feet of gas per day, and has
already produced over 100,000 equivalent barrels since August 2000. This well
is currently producing at rates over 1,000 BOPD. As a result of this success,
additional exploratory wells have been scheduled for drilling in 2001 to
further test the deep geologic model.
International
-------------
In the first nine months 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. In October 2000, the Company transferred a 25%
participating interest in this permit to a large U.S.-based independent oil
and gas company. Nuevo will continue to be the operator of the permit and
currently has a 75% participating interest. The Company plans to drill its
first exploratory well on the concession late this year or early 2001 and
continues to hold discussions with parties considering the acquisition of an
interest in this concession.
15
<PAGE>
NUEVO ENERGY COMPANY
--------------------
Management's Discussion and Analysis of Financial
-------------------------------------------------
Condition and Results of Operations (Continued)
-----------------------------------------------
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 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 December 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 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 December 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 221 development wells, of which 60 were
injectors, in the first nine months of 2000, most of the wells relate to the
interests acquired from Texaco in 1999. The Company completed the first phase
of its development-drilling program on its Cymric Field Star Fee property
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 65 wells. The Company expects this program to be
completed by the end of the year. The wells drilled to date are currently
producing at a combined rate of 5,800 BOPD. Year to date, the Company drilled
133 wells on its Cymric Field (four of which were horizontal wells and 21 of
which were steam injectors), 45 wells on its Belridge Field (ten of which
were horizontal wells and 33 of which were steam injectors), and 37 wells at
Midway Sunset (one of which was horizontal and six of which were injectors).
In addition to the development activity in California, the Company
successfully drilled two offshore wells at its Huntington Beach Field. These
two wells have been completed and are producing 600 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 start-up of the first self-
generation project has resulted in significant cost savings for the Brea
Olinda property to date. 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
16
<PAGE>
NUEVO ENERGY COMPANY
--------------------
Management's Discussion and Analysis of Financial
-------------------------------------------------
Condition and Results of Operations (Continued)
-----------------------------------------------
operations and help reduce expenses in the long-term. The Company expects
this plant to be online and operational by year-end.
International
-------------
During the first nine months of 2000, the Company drilled its first
horizontal test well on its Martin Hill project in Alberta, Canada. The
Company has a 50% interest in over 22,000 acres on this project. The Company
plans to install a steam generator and begin a pilot thermal process that
will be conducted this winter to test this zone.
Derivative Financial Instruments
--------------------------------
The Company utilizes derivative financial instruments to reduce its exposure
to decreases 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 September 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
$32.6 million and $16.5 million in the third quarter of 2000 and 1999,
respectively. For the first nine months of 2000 and 1999, oil and gas
revenues were reduced by $83.9 million and $25.3 million, respectively, as a
result of hedging transactions.
In 1999, the Company entered into a swap arrangement with a major financial
institution that effectively converted 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 addition, the swap arrangement effectively
set the price at which the Company could repurchase these Notes. In the third
quarter of 2000, this swap arrangement was settled, resulting in no
significant impact to the Company's results of operations.
For 2000, the Company entered into swap contracts on 16,500 BOPD, at an
average West Texas Intermediate ("WTI") price of $17.94 per barrel. The
Company also entered into cost-less 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 September 30, 2000, the market value of
these hedge positions was a loss of approximately $28.1 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 September 30, 2000, the market value of these swaps was
a loss of $64.0 million.
17
<PAGE>
NUEVO ENERGY COMPANY
--------------------
Management's Discussion and Analysis of Financial
-------------------------------------------------
Condition and Results of Operations (Continued)
-----------------------------------------------
For 2002, the Company has entered into swap arrangements on 12,500 BOPD for
the first quarter at an average WTI price of $25.91 per barrel. For the
remainder of 2002, the Company purchased put options with a strike price of
$22.00 per barrel WTI, on 19,000 BOPD for the second quarter, and on 14,000
BOPD for both the third and fourth quarters. At September 30, 2000, the
market value of these hedge positions is a gain of $0.3 million. All of 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.
Crude Oil Agreement
-------------------
In February 2000, the Company entered into a 15-year contract, effective
January 1, 2000, to sell all of its current and future California crude oil
production to Tosco Corporation. The contract provides pricing based on a
fixed percentage of the NYMEX crude oil price for each type of crude oil that
Nuevo produces in California. While the contract does not reduce the
Company's exposure to price volatility, it does effectively eliminate the
basis differential risk between the NYMEX price and the field price of the
Company's California oil production.
18
<PAGE>
NUEVO ENERGY COMPANY
--------------------
Management's Discussion and Analysis of Financial
-------------------------------------------------
Condition and Results of Operations (Continued)
-----------------------------------------------
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 the near month 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.
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 28% of the gross Point Pedernales production, or 34% of its net
Point Pedernales production.
19
<PAGE>
NUEVO ENERGY COMPANY
--------------------
Management's Discussion and Analysis of Financial
-------------------------------------------------
Condition and Results of Operations (Continued)
-----------------------------------------------
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 that changes in the derivative's fair
value be recognized currently in earnings unless specific hedge accounting
criteria are met. Accounting for qualifying hedges allows derivative gains
and losses to be reported in other comprehensive income until the hedged
transaction occurs, and requires formal documentation and assessment of the
effectiveness of transactions that receive hedge accounting.
The Company must adopt SFAS No. 133 by January 1, 2001, and does not plan to
adopt early. On adoption, the provisions of this statement must be applied
prospectively. The Company has completed an inventory of all known
derivatives and is in the process of documenting the relevant hedge
relationships. The Company expects that the adoption of SFAS No. 133 will
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. Although the Company currently
believes that its derivative financial instruments will qualify for hedge
accounting under SFAS No. 133, the Company has not yet determined the impact
of the implementation of this statement on its financial condition or results
of operations.
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 September 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 had deferred tax assets, net of valuation allowances, of $17.9
million and $24.0 million as of September 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.
20
<PAGE>
NUEVO ENERGY COMPANY
--------------------
Management's Discussion and Analysis of Financial
-------------------------------------------------
Condition and Results of Operations (Continued)
-----------------------------------------------
Results of Operations (Three months ended September 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 September 30, %
-------------------
Increase/
2000 1999 (Decrease)
------ ------ ---------
<S> <C> <C> <C>
Production:
Oil and condensate - Domestic (MBBLS)...................... 3,999 3,962 1%
Oil and condensate - International (MBBLS)................. 479 501 (4%)
------ ------
Oil and condensate - Total (MBBLS)......................... 4,478 4,463 0%
Natural gas - Domestic (MMCF).............................. 3,636 4,926 (26%)
Natural gas liquids - Domestic (MBBLS)..................... 48 54 (11%)
Equivalent barrels of production - Domestic (MBOE)......... 4,652 4,837 (4%)
Equivalent barrels of production - International (MBOE).... 479 501 (4%)
------ ------
Equivalent barrels of production - Total (MBOE)............ 5,131 5,338 (4%)
Average Sales Price:
Oil and condensate - Domestic.............................. $14.51 $11.39 27%
Oil and condensate - International......................... $19.07 $19.62 (3%)
Oil and condensate - Total................................. $15.00 $12.31 22%
Natural gas - Domestic..................................... $ 5.24 $ 2.53 107%
Lease Operating Expense:
Average unit production cost/(1)/ per BOE - Domestic....... $ 7.46 $ 6.78 10%
Average unit production cost/(1)/ per BOE - International.. $ 7.31 $ 5.65 29%
Average unit production cost/(1)/ per BOE - Total.......... $ 7.45 $ 6.67 12%
</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 three months ended September 30, 2000, were $87.3
million, or 27% higher than oil and gas revenues for the same period in 1999.
This increase is primarily due to a 22% increase in realized oil prices and a
107% increase in realized gas prices. These increases were partially offset by a
26% decrease in gas production, which was primarily attributable to asset sales
and natural field declines from reduced capital spending. Third quarter 2000 oil
price realizations reflect hedging losses of $32.6 million, or $7.27 per barrel,
compared to third quarter 1999 hedging losses of $16.5 million, or $3.70 per
barrel.
The Company recorded three non-recurring items during the third quarter of 2000,
which together have a net immaterial impact on oil and gas revenues. The first
non-recurring item was a $3.5 million decrease (net of royalties) in gas
revenues resulting from a metering error in the Company's Monument Junction
Field in California. This metering error overstated gas volumes and occurred
over a two and a half-year period. The error was identified and corrected in the
third quarter of 2000. The overstatement associated with this adjustment was
also recorded in lease
21
<PAGE>
NUEVO ENERGY COMPANY
--------------------
Management's Discussion and Analysis of Financial
-------------------------------------------------
Condition and Results of Operations (Continued)
-----------------------------------------------
operating expenses (see "Lease Operating Expenses" below), as the Company
consumes the Monument Junction gas production in its thermal operations at
nearby fields. The second non-recurring item was a $2.1 million revenue
receivable for royalties that had been overpaid in prior periods. This item is
reflected as an increase in oil revenues. The third non-recurring item was a
$1.3 million gas balancing receivable that increased gas revenues. This gas
balancing receivable related to production from Four Isle Dome since 1997.
Domestic: Oil and gas revenues for the three months ended September 30, 2000,
--------
were 32% higher than oil and gas revenues for the same period in 1999. This
increase is primarily due to a 27% improvement in average realized oil prices
and a 107% improvement in average realized gas prices, partially offset by a 26%
decrease in gas production. The realized oil price of $14.51 per barrel for the
third quarter of 2000 includes negative hedging results of $8.39 per barrel of
oil, compared to negative hedging results of $4.30 per barrel of oil for the
third quarter of 1999.
International: Oil revenues for the three months ended September 30, 2000,
-------------
decreased 7% as compared to the same period in 1999. This decrease resulted
from a 3% decrease in oil price realizations to $19.07 per barrel, coupled with
a 4% decrease in oil production. The realized oil price for the third quarter of
2000 includes hedging gains of $2.06 per barrel of oil, compared to hedging
gains of $1.06 per barrel in the third quarter of 1999.
Loss/Gain on Sale of Assets, net:
The net loss on sale of assets for the three months ended September 30, 2000,
was $0.5 million, primarily representing a $1.2 million loss on the sale of
certain non-core East Texas Chalk properties, which was partially offset by a
$0.7 million gain on the sale of a waste water disposal plant site in
California. Gain on sale of assets, net, for the three months ended September
30, 1999, was $(0.3) million, representing a negative revision for final
accounting adjustments in connection with the Company's sale of the Illini
pipeline and certain insignificant oil and gas properties.
Interest and Other Income:
Interest and other income for the three months ended September 30, 2000,
includes $1.5 million for a partial reimbursement of previously expensed funds,
resulting from a negotiated settlement of a legal claim (see Note 7 to the Notes
to Condensed Consolidated Financial Statements), as well as several individually
insignificant items. Interest and other income for the three months ended
September 30, 1999, includes a $0.6 million gain on the sale of an
unconsolidated subsidiary, as well as several individually insignificant items.
Expenses
Lease Operating Expenses:
Lease operating expenses for the three months ended September 30, 2000, were
$38.2 million, or 7% higher than for the three months ended September 30, 1999.
Lease operating expenses per barrel of oil equivalent ("BOE") were $7.45 in the
third quarter of 2000, compared to $6.67 in the same period in 1999. The
increase is primarily due to a $7.6 million increase in steam costs resulting
from higher natural gas prices and an increase in gas volumes consumed in
connection with the Company's thermal operations at its Star Fee lease in the
Cymric Field. Offsetting this increase in steam costs is a $3.8 million
downward adjustment to steam costs that resulted from a metering error at the
Company's Monument Junction Field. This error overstated gas volumes and
occurred over a two and a half-year period. The error was identified and
corrected in the third quarter of 2000. The overstatement associated with this
adjustment was also recorded in gas revenues (see "Oil and Gas Revenues" above),
as the Company produces the Monument Junction gas that is consumed in its
thermal operations.
Domestic: Lease operating expenses per BOE were $7.46 in the third quarter of
2000, compared to $6.78 in the same period in 1999. Higher steam costs
contributed to the higher lease operating expenses per BOE quarter over quarter.
22
<PAGE>
NUEVO ENERGY COMPANY
--------------------
Management's Discussion and Analysis of Financial
-------------------------------------------------
Condition and Results of Operations (Continued)
-----------------------------------------------
International: Lease operating expenses per BOE were $7.31 in the third quarter
of 2000, compared to $5.65 in the same period in 1999. This increase is due to
an increase in workovers, as well as the resulting 4% decrease in production.
Exploration Costs:
Exploration costs, including geological and geophysical ("G&G") costs, dry hole
costs, delay rentals and expensed project costs, were $0.8 million and $0.6
million for the three months ended September 30, 2000 and 1999, respectively.
For the three months ended September 30, 2000, exploration costs were comprised
of $0.7 million in G&G (primarily for consulting costs and 2-D seismic
processing in California) and $0.1 million of miscellaneous project costs. For
the three months ended September 30, 1999, exploration costs were comprised of
$0.3 million of expensed project costs, $0.2 million in G&G, and $0.1 million in
delay rentals.
General and Administrative Expenses:
General and administrative expenses were $3.9 million and $4.6 million in the
three months ended September 30, 2000 and 1999, respectively. The 15% decrease
is due primarily to a $0.5 million decrease in the fair market value of
securities in the Company's deferred compensation plan. The remaining decrease
is made up of individually insignificant items.
Interest Expense:
Interest expense of $9.8 million for the three months ended September 30, 2000,
increased 23% as compared to interest expense in the same period in 1999. The
increase is primarily attributable to an increase in outstanding borrowings
under the Company's credit facility plus higher interest rates on those
outstanding borrowings during the third quarter of 2000. On September 26, 2000,
all borrowings outstanding under the credit facility were paid off with net
proceeds received from the Company's issuance of the 9 3/8% Notes (see Note 5 to
the Notes to Condensed Consolidated Financial Statements).
Other Expense:
The $2.9 million decrease in other expense from the third quarter of 1999 to the
third quarter of 2000 relates to $2.9 million of third-party fees incurred in
the third quarter of 1999 in connection with the exchange of the Company's
senior subordinated notes.
Net Income (Loss)
-----------------
Net income of $7.5 million, $0.43 per common share - basic and $0.42 per common
share - diluted, was reported for the three months ended September 30, 2000, as
compared to a net loss of $2.8 million, $0.14 per common share - basic and
diluted, reported for the same period in 1999.
23
<PAGE>
NUEVO ENERGY COMPANY
--------------------
Management's Discussion and Analysis of Financial
-------------------------------------------------
Condition and Results of Operations (Continued)
-----------------------------------------------
Results of Operations (Nine months ended September 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>
Nine Months
Ended September 30, %
-------------------
Increase/
2000 1999 (Decrease)
------- ------- ---------
<S> <C> <C> <C>
Production:
Oil and condensate - Domestic (MBBLS)...................... 11,352 11,777 (4%)
Oil and condensate - International (MBBLS)................. 1,457 1,350 8%
------- -------
Oil and condensate - Total (MBBLS)......................... 12,809 13,127 (2%)
Natural gas - Domestic (MMCF).............................. 11,447 13,153 (13%)
Natural gas liquids - Domestic (MBBLS)..................... 133 147 (10%)
Equivalent barrels of production - Domestic (MBOE)......... 13,393 14,116 (5%)
Equivalent barrels of production - International (MBOE).... 1,457 1,350 8%
------- -------
Equivalent barrels of production - Total (MBOE)............ 14,850 15,466 (4%)
Average Sales Price:
Oil and condensate - Domestic.............................. $ 13.61 $ 9.58 42%
Oil and condensate - International......................... $ 21.35 $ 15.37 39%
Oil and condensate - Total................................. $ 14.49 $ 10.17 42%
Natural gas - Domestic..................................... $ 3.65 $ 2.12 72%
Lease Operating Expense:
Average unit production cost/(1)/ per BOE - Domestic....... $ 6.96 $ 6.14 13%
Average unit production cost/(1)/ per BOE - International.. $ 7.12 $ 6.78 5%
Average unit production cost/(1)/ per BOE - Total.......... $ 6.98 $ 6.20 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 nine months ended September 30, 2000, were $230.7
million, or 40% higher than oil and gas revenues for the same period in 1999.
This increase is primarily due to a 42% increase in realized oil prices and a
72% 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 nine month 2000 oil price realizations reflect hedging losses of
$83.9 million, or $6.55 per barrel, compared to hedging losses of $25.3 million,
or $1.93 per barrel in the first nine months of 1999.
Domestic: Oil and gas revenues for the nine months ended September 30, 2000,
--------
were 38% higher than oil and gas revenues for the same period in 1999. This
increase is primarily due to a 42% improvement in average realized oil prices
and a 72% improvement in average realized gas prices, partially offset by a 13%
decrease in gas production and a 4% decrease in oil production. The 5% decrease
in total production is a result of asset sales, reduced capital
24
<PAGE>
NUEVO ENERGY COMPANY
--------------------
Management's Discussion and Analysis of Financial
-------------------------------------------------
Condition and Results of Operations (Continued)
-----------------------------------------------
spending in 1999 and production interruptions due to pump replacements and
brown-outs in California during recent periods of extreme temperatures. The
realized oil price of $13.61 per barrel for the first nine months of 2000
includes negative hedging results of $86.9 million, or $7.66 per barrel of oil,
compared to hedging losses of $26.7 million, or $2.26 per barrel in the first
nine months of 1999.
International: Oil revenues for the nine months ended September 30, 2000,
-------------
increased 50% compared to the same period in 1999. This significant increase
resulted from a 39% increase in oil price realizations to $21.35 per barrel,
coupled with an 8% increase in oil production. The realized oil price for the
first nine months of 2000 includes hedging gains of $3.0 million, or $2.08 per
barrel of oil, compared to hedging gains of $1.4 million, or $1.01 per barrel in
the first nine months of 1999.
Loss/Gain on Sale of Assets, net:
The net loss on sale of assets for the nine months ended September 30, 2000, was
$14,000, primarily representing a $1.2 million loss on the sale of certain non-
core East Texas Chalk properties, which was almost entirely offset by a $0.7
million gain on the sale of a waste water disposal plant site in California and
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 nine months ended September 30, 1999, was $80.0 million, primarily
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 nine months ended September 30, 2000, includes
$1.5 million for a partial reimbursement of previously expensed funds, resulting
from a negotiated settlement of a legal claim (see Note 7 to the Notes to
Condensed Consolidated Financial Statements), as well as several individually
insignificant items. Interest and other income for the nine months ended
September 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 plus a $0.6 million gain
on the sale of an unconsolidated subsidiary, as well as several individually
insignificant items.
Expenses
--------
Lease Operating Expenses:
Lease operating expenses for the nine months ended September 30, 2000, were
$103.6 million, or 8% higher than for the nine months ended September 30, 1999.
This increase is primarily due to a $10.8 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 $6.98 in the first
nine months of 2000, compared to $6.20 in the same period in 1999. The per
barrel increase is primarily due to a $0.76 per BOE increase in steam costs, as
well as the 4% decrease in total production.
Domestic: Lease operating expenses per BOE were $6.96 in the first nine months
--------
of 2000, compared to $6.14 in the same period in 1999. Higher steam costs
accounted for $0.86 of the per BOE increase, partially offset by lower field
costs. The remaining increase is attributable to the 5% decrease in production.
International: Lease operating expenses per BOE were $7.12 in the first nine
-------------
months of 2000, compared to $6.78 in the same period in 1999. The increase in
lease operating expenses per BOE is primarily attributable to the 8% increase in
production.
Exploration Costs:
Exploration costs, including G&G costs, dry hole costs, delay rentals and
expensed project costs, were $5.5 million and $10.6 million for the nine months
ended September 30, 2000 and 1999, respectively. For the nine months ended
September 30, 2000, exploration costs were comprised of $4.4 million in G&G
(primarily for 3-D seismic acquisition and processing in the Accra-Keta prospect
offshore Ghana), $0.8 million of other project costs, $0.2 million in delay
25
<PAGE>
NUEVO ENERGY COMPANY
--------------------
Management's Discussion and Analysis of Financial
-------------------------------------------------
Condition and Results of Operations (Continued)
-----------------------------------------------
rentals, and $0.1 million in dry hole costs,. For the nine months ended
September 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), $1.7
million in G&G, $1.2 million of expensed project costs, and $0.4 million in
delay rentals.
Depreciation, Depletion and Amortization:
Depreciation, depletion and amortization for the nine months ended September 30,
2000, reflects a 22% 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 $13.4 million and $11.8 million for the
nine months ended September 30, 2000 and 1999, respectively. The 13% increase
is due primarily to a $1.4 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 $26.6 million for the nine months ended September 30, 2000,
increased 9% as compared to interest expense in the same period in 1999. The
increase is primarily attributable to an increase in outstanding borrowings
under the Company's credit facility plus higher interest rates on those
outstanding borrowings. On September 26, 2000, all borrowings outstanding under
the credit facility were paid off with net proceeds received from the Company's
issuance of the 9 3/8% Notes (see Note 5 to the Notes to Condensed Consolidated
Financial Statements). The increase is also due 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 31% decrease in other expense from the first nine months of 1999 to the
first nine months of 2000 is due to a number of items. In 1999, the Company
incurred $2.9 million of third-party fees in the third quarter of 1999 in
connection with the exchange of its senior subordinated notes. Additionally, 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. In 2000, the Company recorded a $2.0
million accrual for a lawsuit settlement (see Note 7 to the Notes to Condensed
Consolidated Financial Statements) and $0.8 million in costs to evaluate
potential business transactions. The remaining decrease is made up of
individually insignificant items.
Net Income
----------
Net income of $9.0 million, $0.51 per common share - basic and $0.50 per common
share - diluted, was reported for the nine months ended September 30, 2000, as
compared to net income of $13.0 million, $0.66 per common share - basic and
$0.65 per common share - diluted, reported for the same period in 1999.
26
<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.
27
<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 6. Exhibits and Reports on Form 8-K
------ --------------------------------
(a) Exhibits
3. Articles of Incorporation and bylaws.
3.1 Certificate of Incorporation of Nuevo Energy Company
(Incorporated by reference from Exhibit 3.1 to Quarterly Report
on Form 10-Q for the quarterly period ended June 30, 1999).
3.2 Certificate of Amendment to the Certificate of Incorporation of
Nuevo Energy Company (Incorporated by reference from Exhibit 3.2
to Quarterly Report on Form 10-Q for the quarterly period ended
June 30, 1999).
3.3 Bylaws of Nuevo Energy Company (Incorporated by reference from
Exhibit 3.3 to Quarterly Report on Form 10-Q for the quarterly
period ended June 30, 1999).
3.4 Amendment to section 3.1 of the Bylaws of Nuevo Energy Company
(Incorporated by reference from Exhibit 3.4 to Quarterly Report
on Form 10-Q for the quarterly period ended June 30, 1999).
4. Instruments defining the rights of security holders, including
indentures
4.12 Indenture dated September 26, 2000, between Nuevo Energy Company
and State Street Bank and Trust Company as the Trustee - 9 3/8%
Senior Subordinated Notes due 2010.
4.13 Registration Agreement dated September 26, 2000 between Nuevo
Energy Company, Banc of America Securities LLC, Banc One Capital
Markets, Inc. and J.P. Morgan & Co.
27. Financial Data Schedule
(b) Reports on Form 8-K
No reports on Form 8-K have been filed during the three-month period ended
September 30, 2000.
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: November 14, 2000 By:/s/ Douglas L. Foshee
----------------- ---------------------------------
Douglas L. Foshee
Chairman, President and Chief Executive
Officer
Date: November 14, 2000 By:/s/ Robert M. King
----------------- ---------------------------------
Robert M. King
Senior Vice President and Chief Financial
Officer
29
