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, 2001
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 8, 2001, the number of outstanding shares of the Registrant's
common stock was 16,996,112.
NUEVO ENERGY COMPANY
INDEX
PAGE
NUMBER
------
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
Condensed Consolidated Balance Sheets:
September 30, 2001 (Unaudited) and December 31, 2000.................... 3
Condensed Consolidated Statements of Operations (Unaudited):
Three and nine months ended September 30, 2001 and September 30, 2000... 4
Condensed Consolidated Statements of Cash Flows (Unaudited):
Nine months ended September 30, 2001 and September 30, 2000............. 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....... 23
PART II. OTHER INFORMATION............................................... 24
2
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Amounts in Thousands, Except Share Data)
September 30, 2001 December 31, 2000
------------------- ------------------
ASSETS (Unaudited)
CURRENT ASSETS:
Cash and cash equivalents............................................................... $ 2,888 $ 39,447
Accounts receivable, net................................................................ 56,102 71,777
Product inventory....................................................................... 2,561 3,230
Prepaid expenses and other.............................................................. 11,567 4,042
---------- ----------
Total current assets.................................................................. 73,118 118,496
---------- ----------
PROPERTY AND EQUIPMENT, AT COST:
Land.................................................................................... 58,807 53,246
Oil and gas properties (successful efforts method)...................................... 1,231,707 1,102,233
Gas plant facilities.................................................................... 8,723 12,020
Other facilities........................................................................ 14,214 12,907
---------- ----------
1,313,451 1,180,406
Accumulated depreciation, depletion and amortization.................................... (556,591) (496,444)
---------- ----------
756,860 683,962
---------- ----------
DEFERRED TAX ASSETS, NET................................................................. 9,650 16,282
OTHER ASSETS............................................................................. 25,423 29,284
---------- ----------
$ 865,051 $ 848,024
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable....................................................................... $ 21,308 $ 25,895
Accrued interest....................................................................... 15,278 5,757
Accrued drilling costs................................................................. 20,829 12,467
Accrued lease operating costs.......................................................... 27,395 30,037
Other accrued liabilities.............................................................. 8,367 17,668
---------- ----------
Total current liabilities.......................................................... 93,177 91,824
---------- ----------
LONG-TERM DEBT, NET OF CURRENT MATURITIES................................................ 409,577 409,727
OTHER LONG-TERM LIABILITIES.............................................................. 7,093 8,356
COMMITMENTS AND CONTINGENCIES (NOTE 6)
COMPANY-OBLIGATED MANDATORILY
REDEEMABLE CONVERTIBLE PREFERRED
SECURITIES OF NUEVO FINANCING I........................................................ 115,000 115,000
STOCKHOLDERS' EQUITY:
Common stock, $.01 par value, 50,000,000 shares authorized, 20,905,796 and 20,620,296
shares issued and 16,880,080 and 16,632,318 shares outstanding at September 30, 2001
and December 31, 2000, respectively................................................... 209 206
Additional paid-in capital............................................................. 366,479 361,643
Treasury stock, at cost, 3,909,684 and 3,813,074 shares, at
September 30, 2001 and December 31, 2000, respectively.............................. (76,275) (74,703)
Stock held by benefit trust, 116,032 and 174,904 shares, at
September 30, 2001 and December 31, 2000, respectively.............................. (2,565) (3,646)
Deferred stock compensation............................................................ (724) (602)
Other comprehensive income............................................................. 2,982 ---
Accumulated deficit.................................................................... (49,902) (59,781)
---------- ----------
Total stockholders' equity......................................................... 240,204 223,117
---------- ----------
$ 865,051 $ 848,024
========== ==========
See accompanying notes to condensed consolidated financial statements.
3
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(Amounts in Thousands, Except per Share Data)
Three Months Ended
September 30,
------------------
2001 2000
------- -------
REVENUES:
Oil and gas revenues............................ $82,584 $90,002
Gain on sale of assets, net..................... 78 ---
Interest and other income....................... 481 2,264
------- -------
83,143 92,266
------- -------
COSTS AND EXPENSES:
Lease operating expenses........................ 40,167 38,526
Exploration costs............................... 5,959 791
Depreciation, depletion and amortization........ 18,790 18,563
Loss on sale of assets, net..................... --- 520
General and administrative expenses............. 9,502 7,354
Interest expense, net........................... 10,635 9,789
Dividends on Guaranteed Preferred
Beneficial Interests in Company's
Convertible Debentures (TECONS)............... 1,653 1,653
Other expense................................... 321 572
------- -------
87,027 77,768
------- -------
(Loss) income before income taxes................ (3,884) 14,498
(Benefit) provision for income taxes............. (1,501) 5,843
------- -------
NET (LOSS) INCOME................................ $(2,383) $ 8,655
======= =======
(LOSS) EARNINGS PER SHARE:
Basic:
(Loss) earnings per common share................. $(0.14) $0.50
======= =======
Weighted average common shares outstanding....... 16,877 17,425
======= =======
DILUTED:
(Loss) earnings per common share................. $(0.14) $0.48
======= =======
Weighted average common and dilutive potential
common shares outstanding........................ 16,877 17,886
======= =======
See accompanying notes to condensed consolidated financial statements.
4
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(Amounts in Thousands, Except per Share Data)
Nine Months Ended
September 30,
-------------------
2001 2000
-------- --------
REVENUES:
Oil and gas revenues..................................... $299,990 $229,359
Interest and other income................................ 1,427 3,085
-------- --------
301,417 232,444
-------- --------
COSTS AND EXPENSES:
Lease operating expenses................................. 146,492 103,609
Exploration costs........................................ 14,006 5,533
Depreciation, depletion and amortization................. 58,815 49,954
Loss on sale of assets, net.............................. 53 14
General and administrative expenses...................... 26,007 23,590
Interest expense, net.................................... 32,219 26,596
Dividends on Guaranteed Preferred
Beneficial Interests in Company's
Convertible Debentures (TECONS)........................ 4,959 4,959
Other expense............................................ 2,213 4,419
-------- --------
284,764 218,674
-------- --------
Income before income taxes and cumulative effect.......... 16,653 13,770
Provision for income taxes................................ 6,774 5,550
-------- --------
Earnings before cumulative effect......................... 9,879 8,220
Cumulative effect of a change in accounting principle,
net of related tax benefit of $537..................... --- (796)
-------- --------
NET INCOME................................................ $ 9,879 $ 7,424
======== ========
EARNINGS PER SHARE:
Basic:
Income before cumulative effect.......................... $ 0.59 $ 0.47
Cumulative effect of a change in accounting principle,
net of income tax benefit.............................. --- (0.05)
-------- --------
Net income............................................... $ 0.59 $ 0.42
======== ========
Weighted average common shares outstanding................ 16,686 17,509
======== ========
DILUTED:
Income before cumulative effect.......................... $ 0.57 $ 0.45
Cumulative effect of a change in accounting principle,
net of income tax benefit.............................. --- (0.04)
-------- --------
Net income............................................... $ 0.57 $ 0.41
======== ========
Weighted average common and dilutive potential
common shares outstanding............................. 17,101 18,013
======== ========
See accompanying notes to condensed consolidated financial statements.
5
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in Thousands)
Nine Months Ended
September 30,
----------------------
2001 2000
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income......................................... $ 9,879 $ 7,424
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization...... 58,815 49,954
Impairment of oil and gas properties.......... 1,014 ---
Cumulative effect of a change in accounting
principle, net of income tax benefit......... --- 796
Loss on sale of assets, net................... 53 14
Dry hole costs................................ 6,492 91
Amortization of other costs................... 1,797 1,396
Deferred taxes................................ 6,750 5,922
Other......................................... 272 55
--------- ---------
85,072 65,652
Changes in assets and liabilities:
Accounts receivable.............................. 15,246 (10,771)
Accounts payable and accrued liabilities......... 1,250 5,413
Other............................................ 61 3,650
NET CASH PROVIDED BY OPERATING ACTIVITIES.......... 101,629 63,944
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties................ (104,223) (76,216)
Acquisitions of oil and gas properties............ (28,456) ---
Additions to other facilities..................... (6,868) (2,510)
Proceeds from sales of properties.................. --- 2,584
NET CASH USED IN INVESTING ACTIVITIES.............. (139,547) (76,142)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings........................... 99,950 197,100
Payments of long-term debt........................ (100,100) (128,873)
Deferred financing and modification costs......... (97) (4,964)
Treasury stock purchases.......................... (2,085) (12,540)
Proceeds from issuance of common stock............ 3,691 2,462
--------- ---------
NET CASH PROVIDED BY FINANCING ACTIVITIES.......... 1,359 53,185
--------- ---------
Net (decrease) increase in cash and
cash equivalents................................. (36,559) 40,987
Cash and cash equivalents at beginning of period.. 39,447 10,288
--------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD......... $ 2,888 $ 51,275
========= =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of amounts capitalized)........... $ 20,943 $ 19,143
Income taxes.................................... $ 375 $ ---
See accompanying notes to condensed consolidated financial statements.
6
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 accounting principles generally accepted in the United States.
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, 2001 and December 31, 2000 and
the results of operations and changes in cash flows for the periods ended
September 30, 2001 and 2000. These financial statements should be read in
conjunction with the financial statements and notes to financial statements
in the 2000 Form 10-K of Nuevo Energy Company (the "Company").
USE OF ESTIMATES
In order to prepare these financial statements in conformity with accounting
principles generally accepted in the United States, 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.
DERIVATIVE FINANCIAL INSTRUMENTS
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("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 was effective for the Company beginning January 1, 2001. In
accordance with the transition provisions of SFAS 133, the Company recorded a
net-of-tax cumulative-effect transition adjustment of $(16.0) million (net of
related tax benefit of $10.8 million) in accumulated other comprehensive
income to recognize the fair value of its derivatives designated as cash-flow
hedging instruments at the date of adoption.
All of the Company's derivative instruments are recognized on the balance
sheet at their fair value. The Company currently uses swaps and options to
hedge its exposure to material changes in the future price of crude oil.
At September 30, 2001, the Company had recorded $3.0 million (net of related
tax expense of $2.0 million) of cumulative hedging gains in other
comprehensive income, of which $2.0 million (based on September 30, 2001
forecasted future prices) is expected to be reclassified to earnings within
the next 12 months. The amounts ultimately reclassified to earnings will
vary due to changes in the fair value of the open derivative contracts prior
to settlement.
As a result of hedging transactions, oil and gas revenues were reduced by
$51.0 million and $83.9 million in the first nine months of 2001 and 2000,
respectively. The portion of the Company's hedging transactions that was
ineffective was $0.1 million for the first nine months of 2001 and was
recorded in interest and other income.
For the remainder of 2001, the Company has entered into swap arrangements for
the fourth quarter on 15,500 BOPD at an average WTI price of $22.95 per
barrel. On a physical volume basis, these hedges cover 37% of the Company's
remaining estimated 2001 oil production.
7
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(UNAUDITED)
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 Bbl, on 2,000 BOPD
for the second quarter at an average WTI price of $23.50 per Bbl, on 6,800
BOPD for the third quarter at an average WTI price of $23.20 per Bbl, and
5,000 BOPD for the fourth quarter at an average WTI price of $23.90. The
swap arrangements for the second and third quarter were purchased subsequent
to September 30, 2001, and accordingly are not reflected in the accompanying
financial statements. In addition, for 2002 the Company purchased put
options with a WTI strike price of $22.00 per Bbl on 19,000 BOPD for the
second quarter, and on 14,000 BOPD for both the third and fourth quarters.
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.
In February 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
also effectively hedged the price at which the Company could repurchase these
Notes. This swap arrangement was settled in the third quarter of 2000.
COMPREHENSIVE INCOME
Comprehensive income includes net income and all changes in other
comprehensive income (loss) including, among other things, foreign currency
translation adjustments, unrealized gains and losses on certain investments
in debt and equity securities and changes in the fair value of derivatives
designated as cash-flow hedges. Comprehensive income for the first nine
months of 2001 and 2000 was as follows:
2001 2000
-------- ------
Net income $ 9,879 $7,424
Comprehensive loss (11,515) ---
Reclassification entry 30,473 ---
-------- ------
Total comprehensive income $ 28,837 $7,424
======== ======
RECENT ACCOUNTING PRONOUNCEMENTS
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." SFAS No. 144 addresses the accounting and
reporting for the impairment or disposal of long-lived assets and supersedes
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and Long-
Lived Assets to be Disposed Of" and APB Opinion No. 30, "Reporting the
Results of Operations - Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions." The objective of SFAS No. 144 is to establish one accounting
model for long-lived assets to be disposed of by sale, as well as resolve
implementation issues related to SFAS No. 121. The Company expects to adopt
SFAS No. 144 effective January 1, 2002, and does not expect such adoption to
have a material impact on its financial condition or results of operations.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." The statement requires entities to record the fair value of a
liability for legal obligations associated with the retirement obligations of
tangible long-lived assets in the period in which it is incurred. When the
liability is initially recorded, the entity increases the carrying amount of
the related long-lived asset. Accretion of the liability is
recognized each period, and the capitalized cost is depreciated/depleted over
the useful life of the related asset. Upon settlement of the liability, an
entity either settles the obligation for its recorded amount or incurs a gain
or loss upon settlement. The standard is effective for fiscal years
beginning after June 15, 2002, with earlier application encouraged. The
Company is currently evaluating the effect of adopting SFAS No. 143 on its
financial statements and has not yet determined the timing of adoption.
8
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(UNAUDITED)
INVENTORY VALUATION
Prior to December 2000, the Company recorded inventory relating to quantities
of processed fuel oil and natural gas liquids in storage at current market
pricing. Also, fuel oil in inventory was stated at period-end market prices
less transportation costs, and the Company recognized changes in the market
value of inventory from one period to the next as oil revenues. In December
2000, the staff of the Securities and Exchange Commission announced that
commodity inventories should be carried at lower of cost or market rather
than at market value. As a result, the Company changed its inventory
valuation method to the lower of cost or market in the fourth quarter of
2000, retroactive to the beginning of the year. Accordingly, the Company's
quarterly results for 2000 have been restated to reflect this change in
accounting.
RECLASSIFICATIONS
Certain reclassifications of prior year amounts have been made to conform to
the current presentation.
2. PROPERTY AND EQUIPMENT
The Company utilizes the successful efforts method of accounting for its
investments in oil and gas properties. Under successful efforts, oil and gas
lease acquisition costs and intangible drilling costs associated with
exploration efforts that result in the discovery of proved reserves and costs
associated with development drilling, whether or not successful, are
capitalized when incurred. When a proved property is sold, ceases to produce
or is abandoned, a gain or loss is recognized. When an entire interest in an
unproved property is sold for cash or cash equivalent, gain or loss is
recognized, taking into consideration any recorded impairment. When a partial
interest in an unproved property is sold, the amount received is treated as a
reduction of the cost of the interest retained.
Unproved leasehold costs are capitalized pending the results of exploration
efforts. Significant unproved leasehold costs are reviewed periodically and
a loss is recognized to the extent, if any, that the cost of the property has
been impaired. Exploration costs, including geological and geophysical
expenses, exploratory dry holes and delay rentals, are charged to expense as
incurred.
Costs of successful wells, development dry holes and proved 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 and an
independent consultant, and are included when calculating depreciation and
depletion using the unit-of-production method.
In accordance with SFAS No. 121, the Company reviews its long-lived assets to
be held and used, including proved oil and gas properties accounted for using
the successful efforts method of accounting, on a depletable unit basis
whenever events or circumstances indicate that the carrying value of those
assets may not be recoverable. SFAS No. 121 requires an impairment loss be
recognized when the carrying amount of an asset exceeds the sum of the
undiscounted estimated future cash flows. In this circumstance, the Company
recognizes an impairment loss equal to the difference between the carrying
value and the fair value of the asset. Fair value is estimated to be the
present value of expected future net cash flows from proved reserves,
utilizing a risk-adjusted rate of return.
9
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(UNAUDITED)
3. INDUSTRY SEGMENT INFORMATION
As of September 30, 2001, the Company's oil and gas exploration and
production operations were concentrated primarily in two geographic regions:
domestically, onshore and offshore California, and internationally, offshore
the Republic of Congo in West Africa (the "Congo").
For the Nine Months
Ended September 30,
--------------------
2001 2000
-------- --------
(amounts in
thousands)
Sales to unaffiliated customers:
Oil and gas - Domestic............................. $274,070 $199,550
Oil and gas - International........................ 25,920 29,809
-------- --------
Total sales......................................... 299,990 229,359
Loss on sale of assets, net........................ (53) (14)
Other revenues..................................... 1,427 3,085
-------- --------
Total revenues...................................... $301,364 $232,430
======== ========
Operating profit before income taxes:
Oil and gas - Domestic............................. $ 76,455 $ 61,019
Oil and gas - International........................ 4,169 9,230
-------- --------
80,624 70,249
Unallocated corporate expenses...................... 26,793 24,924
Interest expense, net............................... 32,219 26,596
Dividends on TECONS................................. 4,959 4,959
-------- --------
Income before income taxes and cumulative effect... $ 16,653 $ 13,770
======== ========
Depreciation, depletion and amortization:
Oil and gas - Domestic............................. $ 50,257 $ 42,418
Oil and gas - International........................ 6,881 6,437
Other.............................................. 1,677 1,099
-------- --------
$ 58,815 $ 49,954
======== ========
4. LONG-TERM DEBT
Long-term debt consists of the following (amounts in thousands):
September 30, December 31,
2001 2000
------------- ------------
9 3/8% Senior Subordinated Notes due 2010........ $150,000 $150,000
9 1/2% Senior Subordinated Notes due 2008........ 257,210 257,310
9 1/2% Senior Subordinated Notes due 2006........ 2,367 2,417
-------- --------
Total long-term debt......................... $409,577 $409,577
======== ========
10
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(UNAUDITED)
5. EARNINGS PER SHARE COMPUTATION
SFAS No. 128 requires a reconciliation of the numerator (income) and
denominator (shares) of the basic earnings per share ("EPS") computation to
the numerator and denominator of the diluted EPS computation. In the three-
month period ended September 30, 2001, there were no potentially dilutive
common shares. The Company's reconciliation is as follows (amounts in
thousands):
For the Three Months Ended September 30,
-------------------------------------------------------
2001 2000
------------------------- ------------------------
Loss Shares Income Shares
------- ------ ------- -------
(Loss) earnings per Common share - Basic............... $(2,383) 16,877 $8,655 17,425
Effect of dilutive securities:
Stock options......................................... --- --- --- 297
Benefit Trust.......................................... --- --- (50) 164
------- ------ ------ ------
(Loss) earnings per Common share - Diluted............... $(2,383) 16,877 $8,605 17,886
======= ====== ====== ======
For the Nine Months Ended September 30,
-------------------------------------------------------
2001 2000
------------------------- ------------------------
Income Shares Income Shares
------- ------ ------- -------
Earnings before cumulative effect
per Common share - Basic.............................. $9,879 16,686 $8,220 17,509
Effect of dilutive securities:
Stock options......................................... --- 262 --- 350
Benefit Trust......................................... (194) 153 (35) 154
------ ------ ------ ------
Earnings before cumulative effect
per Common share - Diluted............................ $9,685 17,101 $8,185 18,013
====== ====== ====== ======
Certain of the Company's stock options and benefit trust shares that could
potentially dilute basic EPS in the future were not included in the
computation of diluted EPS because to do so would have been anti-dilutive in
the periods presented.
6. CONTINGENCIES AND OTHER MATTERS
On September 14, 2001 during an annual inspection, the Company discovered
fractures in the heat affected zone of certain flanges on its pipeline that
connects its Point Pedernales field with onshore processing facilities. The
Company elected to shut-in production in the field while repairs are being
made. The daily net production associated with this field is approximately
5,000 barrels of crude oil and 1.2 MMcf of gas, representing approximately
11% of Nuevo's daily production. The Company intends to replace the damaged
flanges, as well as others which have not shown signs of damage at this time.
The cost of repair is expected to be partially covered by insurance. The
Company may have exposure to costs that may not be recoverable from
insurance, including those associated with repair of undamaged equipment.
Such costs are not expected to be material to the Company's operating
results, financial condition or liquidity.
On June 15, 2001, the Company experienced a failure of a carbon dioxide
treatment vessel at the Rincon Onshore Separation Facility ("ROSF") located
in Ventura County, California. There were no injuries associated with this
event and the cause of the failure is under investigation. Crude oil and
natural gas produced from three fields offshore California are transported
onshore by pipeline to the ROSF plant where crude oil and water are separated
and treated, and carbon dioxide is removed from the natural gas stream. The
daily net production associated with these fields is 3,000 barrels of crude
oil and 2.4 MMcf of gas, representing approximately 6% of Nuevo's daily
production. Crude oil production resumed in early July and full gas sales
resumed by mid August. The cost of repair, less a $50,000 deductible, is
expected to be covered by insurance. The Company may have exposure to costs
that may not be recoverable from insurance. Such costs would not be expected
to be material to the Company's operating results, financial condition or
liquidity.
11
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(UNAUDITED)
On September 22, 2000, the Company was named as a defendant in the lawsuit
Thomas Wachtell et. al. v. Nuevo Energy Company et. al. in the Superior Court
of Los Angeles County, California. The Company successfully removed this
lawsuit to the United States District Court for the Central District of
California. The plaintiffs, who own certain interests in the Point Pedernales
properties, have asserted numerous causes of action including breach of
contract, fraud and conspiracy in connection with the plaintiffs' allegations
that: (i) royalties have not been properly paid to them for production from
the Point Pedernales field, (ii) payments have not been made to them related
to production from the Sacate field, and, (iii) the Company has failed to
recognize the plaintiffs interests in the Tranquillon Ridge project. The
plaintiffs have not specified damages. The Company has not yet been required
to file an answer, but believes the allegations are without merit and intends
to vigorously contest these claims. Management does not believe that the
outcome of this matter will have a material adverse impact on the Company's
operating results, financial condition or liquidity.
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. Repairs were completed by the end of
1997, and production recommenced in December 1997. The costs of the clean-up
and the cost to repair the pipeline either have been or are expected to be
covered by insurance held by the Company, less the Company's deductibles of
$120,000. Additionally, the Company has exposure to certain costs that are
expected to be recoverable from insurance, including certain fines,
penalties, and damages, for which the Company has accrued $0.7 million as of
September 30, 2001 and December 31, 2000, as a receivable and payable. The
Company may also have exposure to costs that may not be recoverable from
insurance. 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 has been named as a defendant in certain other lawsuits
incidental to its business. Management does not believe that the outcome of
such litigation will have a material adverse impact on the Company's
operating results or financial condition. However, these actions and claims
in the aggregate seek substantial damages against the Company and are subject
to the inherent uncertainties in any litigation. The Company is defending
itself vigorously in all such matters.
The Company's international investments involve risks typically associated
with investments in emerging markets such as an uncertain political,
economic, legal and tax environment and expropriation and nationalization of
assets. In addition, if a dispute arises in its foreign operations, the
Company may be subject to the exclusive jurisdiction of foreign courts or may
not be successful in subjecting foreign persons to the jurisdiction of the
United States. The Company attempts to conduct its business and financial
affairs so as to protect against political and economic risks applicable to
operations in the various countries where it operates, but there can be no
assurance that the Company will be successful in so protecting itself. A
portion of the Company's investment in the Congo is insured through political
risk insurance provided by the Overseas Private Investment Corporation
("OPIC"). The political risk insurance through OPIC covers up to $25.0
million relating to expropriation and political violence, which is the
maximum coverage available through OPIC. The Company has no deductible for
this insurance.
In connection with their respective February 1995 acquisitions of two
subsidiaries (each a "Congo subsidiary") owning interests in the Yombo field
offshore Congo, the Company and a wholly-owned subsidiary of CMS NOMECO Oil &
Gas Co. ("CMS") agreed with the seller of the subsidiaries not to claim
certain tax losses ("dual consolidated losses") incurred by such subsidiaries
prior to the acquisitions. Under the tax law in the Congo, as it existed when
this acquisition took place, if an entity is acquired in its entirety and
that entity has certain tax attributes, for example tax loss carryforwards
from operations in the Republic of Congo, the subsequent owners of that
entity can continue to utilize those losses without restriction. Pursuant to
the agreement, the Company and CMS may be liable to the seller for the
recapture of dual consolidated losses (net operating losses of any domestic
corporation that are subject to an income tax of a foreign country without
regard to the source of its income or on a residence basis) utilized by the
seller in years prior to the acquisitions if certain triggering events occur,
including (i) a disposition by either the Company or CMS of its respective
Congo subsidiary, (ii) either Congo subsidiary's sale of its interest in the
Yombo field, (iii) the acquisition of
12
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(UNAUDITED)
the Company or CMS by another consolidated group or (iv) the failure of the
Company or CMS's Congo subsidiary to continue as a member of its respective
consolidated group. A triggering event will not occur, however, if a
subsequent purchaser enters into certain agreements specified in the
consolidated return regulations intended to ensure that such dual
consolidated losses will not be claimed. The only time limit associated with
the occurrence of a triggering event relates to the utilization of a dual
consolidated loss in a foreign jurisdiction. A dual consolidated loss that is
utilized to offset income in a foreign jurisdiction is only subject to
recapture for 15 years following the year in which the dual consolidated loss
was incurred for US income tax purposes. The Company and CMS have agreed
among themselves that the party responsible for the triggering event shall
indemnify the other for any liability to the seller as a result of such
triggering event. The Company's potential direct liability could be as much
as $42.5 million if a triggering event with respect to the Company occurs.
Additionally, 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 $61.0 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.
7. ACQUISITIONS
In July 2001, Nuevo entered into a definitive agreement with Coho Anaguid,
Inc, Anadarko Tunisia Anaguid Company, and Pioneer Natural Resources Anaguid
Ltd., to acquire a portion of Coho's interest in the Anaguid Permit, a 1.1
million-acre permit located onshore southern Tunisia in the Ghadames Basin.
Nuevo's 10.42% working interest increased to 22.5%, subject to approval by
the Tunisian government. The Anaguid Permit, operated by Anadarko, is on
trend with the prolific Hassi Berkine and El Borma fields located to the west
in Algeria and Tunisia. Under the current work commitment, a well is expected
to be drilled in the Anaguid Permit during the first quarter of 2002.
In January 2001, the Company acquired approximately 2,900 acres previously
held by Naftex ARM, LLC, in Kern County, California. The Company paid
approximately $28.5 million in connection with this acquisition. The newly
acquired acreage is southeast of the Company's interest in the Cymric field,
and has current production of approximately 1,018 BOE per day, of which more
than half is natural gas. In addition, the acreage provides significant
development potential.
8. DIVESTITURES
As of June 17, 2001, Nuevo relinquished the 1.9 million-acre Accra-Keta
Permit offshore the Republic of Ghana. The Permit was relinquished prior to
the commencement of the second phase of the work program. Nuevo was the
operator of this Permit and held a 50% working interest. An impairment of
$1.0 million was recorded during the second and third quarters of 2001 in
connection with this relinquishment.
In May 2000, the Company sold its working interest in the Las Cienegas field
in California 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.
No impairment charge was recorded upon reclassification to assets held for
sale. In connection with this sale, the Company unwound hedges of 2,800 BOPD
for the period May 2000 through December 2000 and recorded an adjusted net
gain on sale of approximately $0.9 million.
9. SHARE REPURCHASES
On February 12, 2001, Nuevo's Board of Directors authorized the open market
repurchase of an additional 1,000,000 shares of common stock increasing the
amount authorized since December 1997 of up to 5,616,600 shares. Repurchases
may be made at times and at prices deemed appropriate by management and
consistent with the authorization of the Board. During the first quarter of
2001, the Company repurchased 127,800 shares at an average purchase price of
$16.32 per share, including commissions. There were no shares repurchased
during the second or third quarters of 2001. As of September 30, 2001, the
Company had repurchased a total of 3,608,900 shares since December 1997, at
an average purchase price of $16.56 per share, including commissions.
13
NUEVO ENERGY COMPANY
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
FORWARD LOOKING STATEMENTS
This document includes "forward looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended (the "Securities Act"),
and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") and the
Private Securities Litigation Reform Act of 1995. All statements other than
statements of historical facts included in this document are forward-looking
statements, 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. 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 documents filed by the Company with the Securities
and Exchange Commission. All subsequent written and oral forward-looking
statements attributable to the Company or persons acting on its behalf are
expressly qualified by the Cautionary Statements.
CAPITAL RESOURCES AND LIQUIDITY
Since inception, the Company has expanded its operations through a series of
disciplined, low-cost acquisitions of oil and gas properties and the subsequent
exploitation and development of these properties. The Company has complemented
these efforts with divestitures of non-core assets and an opportunistic
exploration program, which provides exposure to high-potential prospects. The
funding of these activities has historically been provided by operating cash
flows, bank financing, private and public placements of debt and equity
securities and property divestitures. Net cash provided by operating activities
was $101.6 million and $63.9 million for the nine months ended September 30,
2001 and 2000, respectively. The Company invested $139.5 million (including
acquisitions of $28.5 million) and $76.1 million in oil and gas properties for
the nine months ended September 30, 2001 and 2000, respectively.
The current borrowing base on the Company's credit facility is $225.0 million.
At September 30, 2001, there were no outstanding borrowings under the revolving
credit agreement. Accordingly, $225.0 million of committed revolving credit
capacity was unused and available at September 30, 2001. At September 30, 2001,
the Company had a working capital deficit of $20.1 million.
On February 12, 2001, Nuevo's Board of Directors authorized the open market
repurchase of an additional 1,000,000 shares of common stock increasing the
amount authorized since December 1997 of up to 5,616,600 shares. Repurchases may
be made at times and at prices deemed appropriate by management and consistent
with the authorization of the Board. During the first quarter of 2001, the
Company repurchased 127,800 shares at an average purchase price of $16.32 per
share, including commissions. There were no shares repurchased during the second
or third quarters of 2001. As of September 30, 2001, the Company had repurchased
a total of 3,608,900 shares since December 1997, at an average purchase price of
$16.56 per share, including commissions.
The Company believes its cash flow from operations and available financing
sources are sufficient to meet its obligations as they become due and to finance
its exploration and development programs.
14
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
CAPITAL EXPENDITURES
The Company anticipates spending an additional $21.8 million on development
activities and an additional $6.3 million on exploration activities and other
capital projects during the remainder of the year.
Exploration and development expenditures, including acquisitions and amounts
expensed under the successful efforts method, for the first nine months of
2001 and 2000 are as follows (amounts in thousands):
For the Nine Months Ended
September 30,
------------------------------------
2001 2000
-------- -------
Domestic $121,651 $75,726
International 20,815 7,536
-------- -------
Total $142,466 $83,262
======== =======
The following is a description of significant exploration and development
activity during the first nine months of 2001.
Exploration Activity
Domestic
Nuevo has drilled to a total depth of 11,914' on the Cutthroat prospect
located 3 1/2 miles to the southeast from the Star Fee 701 discovery. The
well is currently being evaluated. This prospect is targeting the second
Point of Rocks structure.
The Thunderball prospect is currently drilling below 13,200' and has a
programmed total depth of 19,500'. Nuevo holds a 30% working interest with
Occidental of California as operator. This well is targeting the Temblor
formation beneath the Buena Vista Hills field.
Four prospects, Goldeneye, Steelhead, Golden, and Brook, were drilled during
the third quarter in the Buena Vista Hills area and east of the Cymric Field.
All of these wells were dry holes and net dry hole costs to Nuevo totaled
approximately $3.0 million.
International
In early October, Nuevo's operator for the Anaguid Permit, Anadarko,
initiated the acquisition of an additional 303 kilometers of 2-D seismic to
further delineate lead areas that were highlighted from the 1200-kilometer
program completed earlier this year. Nuevo's net cost (22.5% working
interest) is approximately $300,000. The Anaguid Permit is on trend with the
prolific Hassi Berkine and El Borma fields located to the west in Algeria and
Tunisia. Under the current work commitment, a well is scheduled to be drilled
in the Anaguid Permit early next year.
Development Activity
Domestic
With the recent lower gas prices, Nuevo has resumed cyclic steaming
operations on its existing wells. The Company continues to evaluate its plan
for resuming continuous injection and capital spending for new thermal
projects.
Onshore California, the Company's single largest exploitation project in 2001
is the continuing development of its Star Fee acreage in the Cymric Field.
In the first nine months of 2001, this development included drilling 20
Diatomite development wells and one follow-up well to the highly successful
Star Fee 701 well. Star Fee 702 was completed in August and is currently
producing 380 BOE per day from the second Point of Rocks interval.
15
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
International
During the first quarter of 2001, the Company replaced the pipelines from the
two platforms in the Yombo field offshore Congo. The net cost of the
pipeline replacements was approximately $5.3 million. In addition, three
wells were drilled on the B Platform and two wells on the A Platform as part
of a five-well drilling program. These wells have been completed and are
currently producing at a combined rate of approximately 3,900 BOPD.
CALIFORNIA NATURAL GAS AND ELECTRICITY MARKETS
The price of natural gas and the threat of electrical disruptions are factors
that create volatility in the California oil and gas operations. Because of
recent developments, Nuevo has made significant changes in its natural gas
disposition and electricity production in California. Regarding natural gas,
Nuevo has a net long position in California - producing more natural gas than
consumed in thermal crude production. Moreover, as gas shortages occurred in
California during late 2000 and early 2001, Nuevo diverted gas from its
cyclic steaming operations to gas sales. The prices received for these gas
sales were higher than would have been received for oil produced from the
cyclic operations using the gas sold. In the future, Nuevo's sale of its gas
production or use of its gas production to generate steam for its cyclic
operations will depend on market conditions in California for oil and natural
gas.
In California, Nuevo can generate a total of 22.5 Megawatts ("MW") of power
at various sites. Two turbines came on-line at the Company's Brea Olinda
field during 2000 and began using gas that was previously flared. Three
turbines in Kern County can produce 12 MW of power and cogenerate 10% of
Nuevo's total steam needs in thermal operations under normal conditions. By
self-generating power in Kern County, Nuevo has reduced it exposure to rising
electricity prices and unexpected power outages. Nuevo's facilities receive
power under interruptible service contracts. Given the uncertainty of the
California electricity market over the last year, Nuevo's facilities that
receive interruptible service could experience periodic power interruptions.
In addition, the State of California could change existing rules or impose
new rules or regulations with respect to power that could impact the
Company's operating costs.
DERIVATIVE FINANCIAL INSTRUMENTS
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("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 was effective for the Company beginning January 1, 2001. In
accordance with the transition provisions of SFAS 133, the Company recorded a
net-of-tax cumulative-effect transition adjustment of $(16.0) million (net of
related tax benefit of $10.8 million) in accumulated other comprehensive
income to recognize the fair value of its derivatives designated as cash-flow
hedging instruments at the date of adoption.
All of the Company's derivative instruments are recognized on the balance
sheet at their fair value. The Company currently uses swaps and options to
hedge its exposure to material changes in the future price of crude oil.
At September 30, 2001, the Company had recorded $3.0 million (net of related
tax expense of $2.0 million) of cumulative hedging gains in other
comprehensive income, of which $2.0 million (based on September 30, 2001
forecasted future prices) is expected to be reclassified to earnings within
the next 12 months. The amounts ultimately reclassified to earnings will
vary due to changes in the fair value of the open derivative contracts prior
to settlement.
16
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
As a result of hedging transactions, oil and gas revenues were reduced by
$51.0 million and $83.9 million in the first nine months of 2001 and 2000,
respectively. The portion of the Company's hedging transactions that was
ineffective was $0.1 million for the first nine months of 2001 and was
recorded in interest and other income.
For the remainder of 2001, the Company has entered into swap arrangements for
the fourth quarter on 15,500 BOPD at an average WTI price of $22.95 per
barrel. On a physical volume basis, these hedges cover 37% of the Company's
remaining estimated 2001 oil production.
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 Bbl, on 2,000 BOPD
for the second quarter at an average WTI price of $23.50 per Bbl, on 6,800
BOPD for the third quarter at an average WTI price of $23.20 per Bbl, and
5,000 BOPD for the fourth quarter at an average WTI price of $23.90. The swap
arrangements for the second and third quarter were purchased subsequent to
September 30, 2001, and accordingly are not reflected in the accompanying
financial statements. In addition, for 2002 the Company purchased put
options with a WTI strike price of $22.00 per Bbl on 19,000 BOPD for the
second quarter, and on 14,000 BOPD for both the third and fourth quarters.
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.
In February 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
also effectively hedged the price at which the Company could repurchase these
Notes. This swap arrangement was settled in the third quarter of 2000.
RECENT ACCOUNTING PRONOUNCEMENTS
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." SFAS No. 144 addresses the accounting and
reporting for the impairment or disposal of long-lived assets and supersedes
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and Long-
Lived Assets to be Disposed Of" and APB Opinion No. 30, "Reporting the
Results of Operations - Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions." The objective of SFAS No. 144 is to establish one accounting
model for long-lived assets to be disposed of by sale, as well as resolve
implementation issues related to SFAS No. 121. The Company expects to adopt
SFAS No. 144 effective January 1, 2002, and does not expect such adoption to
have a material impact on its financial condition or results of operations.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." The statement requires entities to record the fair value of a
liability for legal obligations associated with the retirement obligations of
tangible long-lived assets in the period in which it is incurred. When the
liability is initially recorded, the entity increases the carrying amount of
the related long-lived asset. Accretion of the liability is
recognized each period, and the capitalized cost is depreciated/depleted over
the useful life of the related asset. Upon settlement of the liability, an
entity either settles the obligation for its recorded amount or incurs a gain
or loss upon settlement. The standard is effective for fiscal years
beginning after June 15, 2002, with earlier application encouraged. The
Company is currently evaluating the effect of adopting SFAS No. 143 on its
financial statements and has not yet determined the timing of adoption.
17
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
RESULTS OF OPERATIONS (THREE MONTHS ENDED SEPTEMBER 30, 2001 AND 2000)
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:
Three Months
Ended September 30, %
------------------- Increase/
2001 2000 (Decrease)
------ ------ ---------
PRODUCTION:
Oil and condensate - Domestic (MBBLS)..................... 3,521 3,999 (12%)
Oil and condensate - International (MBBLS)................ 568 479 19%
------ ------
Oil and condensate - Total (MBBLS)........................ 4,089 4,478 (9%)
Natural gas - Domestic (MMCF)............................. 3,022 3,636 (17%)
Natural gas liquids - Domestic (MBBLS).................... 48 48 ---
Equivalent barrels of production - Domestic (MBOE)........ 4,072 4,652 (12%)
Equivalent barrels of production - International (MBOE)... 568 479 19%
------ ------
Equivalent barrels of production - Total (MBOE)........... 4,640 5,131 (10%)
AVERAGE SALES PRICE:
Oil and condensate - Domestic............................. $16.70 $14.51 15%
Oil and condensate - International........................ $21.79 $24.65 (12%)
Oil and condensate - Total................................ $17.40 $15.60 12%
Natural gas - Domestic.................................... $ 3.45 $ 5.24 (34%)
LEASE OPERATING EXPENSE:
Average unit production cost(1) per BOE - Domestic........ $ 8.67 $ 7.46 16%
Average unit production cost(1) per BOE - International... $ 8.54 $ 7.94 8%
Average unit production cost(1) per BOE - Total........... $ 8.66 $ 7.51 15%
-----------------
(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, 2001, were $82.6
million, or 8% lower than oil and gas revenues for the same period in 2000.
This decrease is primarily due to a 10% decrease in total production as well as
a 34% decrease in gas price realizations, partially offset by a 12% increase in
oil price realizations. Third quarter 2001 oil price realizations reflect
hedging losses of $10.2 million, or $2.49 per barrel compared with hedging
losses of $32.6 million, or $7.27 per barrel in the third quarter of 2000.
Domestic: Oil and gas revenues for the three months ended September 30, 2001,
were 10% lower than oil and gas revenues for the same period in 2000. This
decrease is primarily due to a 12% decrease in total production. The realized
oil price of $16.70 per barrel for the third quarter of 2001 includes negative
hedging results of $2.89 per barrel of oil compared with a realized oil price of
$14.51 per barrel for the third quarter of 2000, which includes negative hedging
results of $8.39 per barrel of oil.
18
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
International: Oil revenues for the three months ended September 30, 2001,
increased 5% as compared to the same period in 2000. This increase relates to
the timing of oil shipments and the recognition of revenue. Current production
is stored and inventory is recorded on the balance sheet at the lower of cost or
market. Revenue is then recognized at the date of shipment. There were no
hedges in place for the third quarter of 2001 relating to international
production. The realized oil price for the third quarter of 2000 includes
hedging gains of $2.06 per barrel of oil.
Other Income:
Interest and other income decreased 79% to $0.5 million for the three months
ended September 30, 2001. The primary reason for the decrease relates to the
payment of $1.5 million to the Company during the third quarter of 2000 in
association with a settlement related to the employee fraud which occurred
during the first quarter of 1999.
Expenses
Lease Operating Expenses:
Lease operating expenses for the three months ended September 30, 2001, were
$40.2 million, or 4% higher than for the three months ended September 30, 2000.
Lease operating expenses per BOE were $8.66 in the third quarter of 2001,
compared to $7.51 in the same period in 2000.
Domestic: Lease operating expenses per BOE were $8.67 in the third quarter of
2001, compared to $7.46 in the same period in 2000. Lower production as well as
increased steam costs contributed to the higher lease operating expenses per BOE
quarter over quarter.
International: Lease operating expenses per BOE were $8.54 in the third quarter
of 2001, compared to $7.94 in the same period in 2000. The increase in lease
operating expenses per BOE is primarily attributable to the timing of oil
shipments and the recognition of associated expenses. Current production is
stored and inventory is recorded on the balance sheet at the lower of cost or
market. Expense is then recognized at the date of shipment.
Exploration Costs:
Exploration costs, including geological and geophysical ("G&G") costs, dry hole
costs, delay rentals and expensed project costs, were $6.0 million and $0.8
million for the three months ended September 30, 2001 and 2000, respectively.
For the three months ended September 30, 2001, exploration costs were comprised
of $0.9 million in G&G (primarily for 2-D seismic processing in California and
in North Africa), $4.5 million in dry hole costs, $0.1 million in impairment
costs associated with the Accra-Keta Prospect, and $0.5 million of other
exploration related activities. 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 of
miscellaneous project costs.
General and Administrative Expenses:
General and administrative expenses were $9.5 million and $7.4 million in the
three months ended September 30, 2001 and 2000, respectively. The 29% increase
is due primarily to certain costs incurred associated with professional
consultation.
Interest Expense:
Interest expense of $10.6 million for the three months ended September 30, 2001,
increased 9% as compared to interest expense in the same period in 2000. The
increase is primarily attributable to the issuance of 9 3/8% Senior Subordinated
Notes due 2010 at the end of the third quarter of 2000, partially offset by a
decrease in outstanding borrowings on the Company's credit facility.
19
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Net (Loss) Income
Net loss of $2.4 million, ($0.14) per common share - basic and diluted, was
reported for the three months ended September 30, 2001, as compared to net
income of $8.7 million, $0.50 and $0.48 per common share - basic and diluted,
respectively, reported for the same period in 2000.
RESULTS OF OPERATIONS (NINE MONTHS ENDED SEPTEMBER 30, 2001 AND 2000)
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:
Nine Months
Ended September 30, %
------------------- Increase/
2001 2000 (Decrease)
------- ------- ---------
PRODUCTION:
Oil and condensate - Domestic (MBBLS)..................... 11,099 11,352 (2%)
Oil and condensate - International (MBBLS)................ 1,353 1,457 (7%)
------- -------
Oil and condensate - Total (MBBLS)........................ 12,452 12,809 (3%)
Natural gas - Domestic (MMCF)............................. 9,803 11,447 (14%)
Natural gas liquids - Domestic (MBBLS).................... 142 133 7%
Equivalent barrels of production - Domestic (MBOE)........ 12,875 13,393 (4%)
Equivalent barrels of production - International (MBOE)... 1,353 1,457 (7%)
------- -------
Equivalent barrels of production - Total (MBOE)........... 14,228 14,850 (4%)
AVERAGE SALES PRICE:
Oil and condensate - Domestic............................. $ 15.80 $ 13.61 16%
Oil and condensate - International........................ $ 19.26 $ 20.46 (6%)
Oil and condensate - Total................................ $ 16.18 $ 14.39 12%
Natural gas - Domestic.................................... $ 9.69 $ 3.65 165%
LEASE OPERATING EXPENSE:
Average unit production cost(1) per BOE - Domestic........ $ 10.61 $ 6.96 52%
Average unit production cost(1) per BOE - International... $ 7.34 $ 7.12 3%
Average unit production cost(1) per BOE - Total........... $ 10.30 $ 6.98 48%
---------------
(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, 2001, were $300.0
million, or 31% higher than oil and gas revenues for the same period in 2000.
This increase is primarily due to a 12% increase in average realized oil prices
and a 165% increase in realized gas prices. These increases were partially
offset by a 7% decrease in international oil production that resulted from two
pipeline replacements in the first quarter of 2001. The first nine months of
2001 oil price realizations reflect hedging losses of $51.0 million, or $4.10
per barrel, compared to hedging losses of $83.9 million, or $6.55 per barrel in
the comparable period of 2000.
20
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Domestic: Oil and gas revenues for the nine months ended September 30, 2001,
were 37% higher than oil and gas revenues for the same period in 2000. This
increase is primarily due to a 165% improvement in average realized gas prices
and a 16% improvement in average realized oil prices. The realized oil price of
$15.80 per barrel for the first nine months of 2001 includes negative hedging
results of $51.0 million, or $4.60 per barrel of oil, compared to hedging losses
of $86.9 million, or $7.66 per barrel in the first nine months of 2000.
International: Oil revenues for the nine months ended September 30, 2001
decreased 13% as compared to the same period in 2000. This decrease relates to
the timing of oil shipments and the recognition of revenue. Current production
is stored and inventory is recorded on the balance sheet at the lower of cost or
market. Revenue is then recognized at the date of shipment. There were no
hedges in place for the third quarter of 2001 relating to international
production. The realized oil price for the first nine months of 2000 includes
hedging gains of $2.08 per barrel of oil.
Expenses
Lease Operating Expenses:
Lease operating expenses for the nine months ended September 30, 2001, were
$146.5 million, or 41% higher than for the nine months ended September 30, 2000.
This increase is primarily due to a $26.0 million increase in steam costs
resulting from higher natural gas prices. Lease operating expenses per BOE were
$10.30 in the first nine months of 2001, compared to $6.98 in the same period in
2000.
Domestic: Lease operating expenses per BOE were $10.61 in the first nine months
of 2001, compared to $6.96 in the same period in 2000. Higher steam costs
accounted for $2.02 of the per BOE increase, period over period. Lower
production also contributed to the higher lease operating expense per BOE,
period over period.
International: Lease operating expenses per BOE were $7.34 in the first nine
months of 2001, compared to $7.12 in the same period in 2000. The slight
increase in lease operating expenses per BOE is primarily attributable to the
timing of oil shipments and the recognition of associated expenses. Current
production is stored and inventory is recorded on the balance sheet at the lower
of cost or market. Expense is then recognized at the date of shipment.
Exploration Costs:
Exploration costs, including G&G costs, dry hole costs, delay rentals and
expensed project costs, were $14.0 million and $5.5 million for the nine months
ended September 30, 2001 and 2000, respectively. For the nine months ended
September 30, 2001, exploration costs were comprised of $6.5 million of dry hole
costs, $5.0 million in G&G (primarily for seismic acquisitions and processing in
California), $0.1 million in delay rentals, $1.0 million in impairment costs
associated with the Accra-Keta prospect, and $1.4 million of other exploration
related activities. 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 rentals, and $0.1 million
in dry hole costs.
Depreciation, Depletion and Amortization:
Depreciation, depletion and amortization for the nine months ended September 30,
2001, reflects an 18% increase from the same period in 2000 due to higher
depletion rates as a result of the decrease in reserve estimates due to higher
gas prices, which are held flat under the SEC reserve case and adversely impact
the economics of the Company's thermally produced oil fields.
21
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
General and Administrative Expenses:
General and administrative expenses were $26.0 million and $23.6 million for the
nine months ended September 30, 2001 and 2000, respectively. The first nine
months of 2001 includes a positive adjustment to bonus accruals for 2000, which
is offset by a $1.6 million severance payment related to the resignation of the
Company's Chairman, President and Chief Executive Officer in May 2001. In
addition, the nine months ended September 30, 2001 include fees incurred
associated with professional consultation.
Interest Expense:
Interest expense of $32.2 million for the nine months ended September 30, 2001,
increased 21% as compared to interest expense in the same period in 2000. The
increase is primarily attributable to the issuance of 9 3/8% Senior Subordinated
Notes due 2010 in the late third quarter of 2000, partially offset by a decrease
in outstanding borrowings on the Company's credit facility.
Other Expense:
The 50% decrease in other expense from the first nine months of 2000 to the
first nine months of 2001 is primarily due to a $2.0 million accrual for a
lawsuit settlement in 2000.
Net Income
Net income of $9.9 million, $0.59 and $0.57 per common share - basic and
diluted, respectively, was reported for the nine months ended September 30,
2001, as compared to net income of $7.4 million, $0.42 and $0.41 per common
share - basic and diluted, respectively, reported for the same period in 2000.
22
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, 2000, 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,
2000.
23
NUEVO ENERGY COMPANY
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Note 6 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,
which can only be accessed from an existing ExxonMobil platform. 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. ExxonMobil contends that Nuevo had not consented to the
operation and therefore cannot receive its share of production from Sacate
until ExxonMobil has first recovered certain costs and fees. As a result,
Nuevo has neither received revenues nor incurred operating expenses related
to Sacate. 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. The
Company's capitalized costs associated with Sacate are insignificant.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) EXHIBITS
10. Material Contracts
10.1 Employment Agreement with James L. Payne
(b) REPORTS ON FORM 8-K
1) A Current Report on Form 8-K, dated October 19, 2001, reporting Item 5.
Other Business and announcing the appointment of James L. Payne as the
company's President, Chairman and Chief Executive Officer was filed on
October 19, 2001.
2) A Current Report on Form 8-K, dated October 17, 2001, reporting Item 9.
Regulation FD Disclosure was filed on October 17, 2001.
3) A Current Report on Form 8-K, dated September 24, 2001, reporting Item
9. Regulation FD Disclosure was filed on September 24, 2001.
4) A Current Report on Form 8-K, dated August 9, 2001, reporting Item 9.
Regulation FD Disclosure was filed on August 9, 2001.
5) A Current Report on Form 8-K, dated July 25, 2001, reporting Item 9.
Regulation FD Disclosure was filed on July 25, 2001.
24
GLOSSARY OF OIL AND GAS TERMS
TERMS USED TO DESCRIBE QUANTITIES OF OIL AND NATURAL GAS
. Bbl -- One stock tank barrel, or 42 US gallons liquid volume, of crude oil
or other liquid hydrocarbons.
. Bcf -- One billion cubic feet of natural gas.
. Bcfe -- One billion cubic feet of natural gas equivalent.
. BOE -- One barrel of oil equivalent, converting gas to oil at the ratio of
6 Mcf of gas to 1 Bbl of oil.
. MBbl -- One thousand Bbls.
. Mcf -- One thousand cubic feet of natural gas.
. MMBbl -- One million Bbls of oil or other liquid hydrocarbons.
. MMcf -- One million cubic feet of natural gas.
. MBOE -- One thousand BOE.
. MMBOE -- One million BOE.
TERMS USED TO CLASSIFY OUR RESERVE QUANTITIES
. Proved reserves -- The estimated quantities of crude oil, natural gas and
natural gas liquids which, upon analysis of geological and engineering data,
appear with reasonable certainty to be recoverable in the future from known
oil and natural gas reservoirs under existing economic and operating
conditions.
The SEC definition of proved oil and gas reserves, per Article 4-10(a)(2) of
Regulation S-X, is as follows:
Proved oil and gas reserves. Proved oil and gas reserves are the estimated
quantities of crude oil, natural gas, and natural gas liquids which geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate is made. Prices
include consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions.
(a) Reservoirs are considered proved if economic producibility is supported
by either actual production or conclusive formation test. The area of a
reservoir considered proved includes (A) that portion delineated by drilling and
defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately
adjoining portions not yet drilled, but which can be reasonably judged as
economically productive on the basis of available geological and engineering
data. In the absence of information on fluid contacts, the lowest known
structural occurrence of hydrocarbons controls the lower proved limit of the
reservoir.
(b) Reserves which can be produced economically through application of
improved recovery, techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.
(c) Estimates of proved reserves do not include the following: (1) oil that
may become available from known reservoirs but is classified separately as
"indicated additional reserves"; (2) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors; (3)
crude oil, natural gas, and natural gas liquids, that may occur in undrilled
prospects; and (4) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
25
. Proved developed reserves -- Proved reserves that can be expected to be
recovered through existing wells with existing equipment and operating
methods.
. Proved undeveloped reserves -- Proved reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where
a relatively major expenditure is required.
TERMS USED TO DESCRIBE THE LEGAL OWNERSHIP OF THE COMPANY'S OIL AND GAS
PROPERTIES
. Royalty interest -- A real property interest entitling the owner to
receive a specified portion of the gross proceeds of the sale of oil and
natural gas production or, if the conveyance creating the interest provides,
a specific portion of oil and natural gas produced, without any deduction
for the costs to explore for, develop or produce the oil and natural gas. A
royalty interest owner has no right to consent to or approve the operation
and development of the property, while the owners of the working interests
have the exclusive right to exploit the mineral on the land.
. Working interest -- A real property interest entitling the owner to
receive a specified percentage of the proceeds of the sale of oil and
natural gas production or a percentage of the production, but requiring the
owner of the working interest to bear the cost to explore for, develop and
produce such oil and natural gas. A working interest owner who owns a
portion of the working interest may participate either as operator or by
voting his percentage interest to approve or disapprove the appointment of
an operator and drilling and other major activities in connection with the
development and operation of a property.
TERMS USED TO DESCRIBE SEISMIC OPERATIONS
. Seismic data -- Oil and gas companies use seismic data as their principal
source of information to locate oil and gas deposits, both to aid in
exploration for new deposits and to manage or enhance production from known
reservoirs. To gather seismic data, an energy source is used to send sound
waves into the subsurface strata. These waves are reflected back to the
surface by underground formations, where they are detected by geophones
which digitize and record the reflected waves. Computers are then used to
process the raw data to develop an image of underground formations.
. 2-D seismic data -- 2-D seismic survey data has been the standard
acquisition technique used to image geologic formations over a broad area.
2-D seismic data is collected by a single line of energy sources which
reflect seismic waves to a single line of geophones. When processed, 2-D
seismic data produces an image of a single vertical plane of sub-surface
data.
. 3-D seismic -- 3-D seismic data is collected using a grid of energy
sources, which are generally spread over several miles. A 3-D survey
produces a three dimensional image of the subsurface geology by collecting
seismic data along parallel lines and creating a cube of information that
can be divided into various planes, thus improving visualization.
Consequently, 3-D seismic data is a more reliable indicator of potential oil
and natural gas reservoirs in the area evaluated.
THE COMPANY'S MISCELLANEOUS DEFINITIONS
. Infill drilling - Infill drilling is the drilling of an additional well or
additional wells in excess of those provided for by a spacing order in order
to more adequately drain a reservoir.
. No. 6 fuel oil (Bunker) - No. 6 fuel oil is a heavy residual fuel oil used
by ships, industry, and for large-scale heating installations.
26
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 13, 2001 By: /s/James L. Payne
----------------------------------
President, Chief Executive Officer
and Chairman
Date: November 13, 2001 By: /s/Robert M. King
----------------------------------
Senior Vice President and
Chief Financial Officer
27