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 MARCH 31, 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 May 10, 2001, the number of outstanding shares of the Registrant's common
stock was 16,702,099.
NUEVO ENERGY COMPANY
INDEX
PAGE
NUMBER
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
Condensed Consolidated Balance Sheets:
March 31, 2001 (Unaudited) and December 31, 2000.............. 3
Condensed Consolidated Statements of Operations (Unaudited):
Three months ended March 31, 2001and March 31, 2000........... 4
Condensed Consolidated Statements of Cash Flows (Unaudited):
Three months ended March 31, 2001and March 31, 2000........... 5
Notes to Condensed Consolidated Financial Statements (Unaudited) 6
ITEM 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations..................................... 12
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk...... 19
PART II. OTHER INFORMATION............................................... 20
2
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Amounts in Thousands)
March 31, 2001 December 31, 2000
-------------- -----------------
ASSETS (Unaudited)
------
CURRENT ASSETS:
Cash and cash equivalents................................................................... $ 16,822 $ 39,447
Accounts receivable, net.................................................................... 85,730 71,777
Product inventory........................................................................... 5,898 3,230
Current deferred tax asset.................................................................. 11,424 ---
Prepaid expenses and other.................................................................. 3,459 4,042
---------- ----------
Total current assets....................................................................... 123,333 118,496
---------- ----------
PROPERTY AND EQUIPMENT, AT COST:
Land........................................................................................ 53,793 53,246
Oil and gas properties (successful efforts method).......................................... 1,151,918 1,102,233
Gas plant facilities........................................................................ 12,020 12,020
Other facilities............................................................................ 13,013 12,907
---------- ----------
1,230,744 1,180,406
Accumulated depreciation, depletion and amortization........................................ (516,279) (496,444)
---------- ----------
714,465 683,962
---------- ----------
DEFERRED TAX ASSETS, NET..................................................................... 9,193 16,282
OTHER ASSETS................................................................................. 30,019 29,284
---------- ----------
$ 877,010 $ 848,024
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
CURRENT LIABILITIES:
Accounts payable........................................................................... $ 27,069 $ 25,895
Accrued interest........................................................................... 15,440 5,757
Accrued liabilities........................................................................ 85,769 60,172
---------- ----------
Total current liabilities................................................................ 128,278 91,824
---------- ----------
LONG-TERM DEBT, NET OF CURRENT MATURITIES.................................................... 409,702 409,727
OTHER LONG-TERM LIABILITIES.................................................................. 8,513 8,356
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, 20,620,796 and 20,620,296
shares issued and 16,506,268 and 16,632,318 shares outstanding at March 31, 2001 and
December 31, 2000, respectively........................................................... 206 206
Additional paid-in capital................................................................. 361,643 361,643
Treasury stock, at cost, 3,934,250 and 3,813,074 shares, at
March 31, 2001 and December 31, 2000, respectively........................................ (76,718) (74,703)
Stock held by benefit trust, 180,278 and 174,904 shares, at
March 31, 2001 and December 31, 2000, respectively........................................ (3,716) (3,646)
Deferred stock compensation................................................................ (528) (602)
Other comprehensive loss................................................................... (15,192) ---
Accumulated deficit........................................................................ (50,178) (59,781)
---------- ----------
Total stockholders' equity.............................................................. 215,517 223,117
---------- ----------
$ 877,010 $ 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 March 31,
----------------------------
2001 2000
-------- -------
REVENUES:
Oil and gas revenues............................ $119,231 $70,739
Gain on sale of assets, net..................... --- 140
Interest and other income....................... 698 626
-------- -------
119,929 71,505
-------- -------
COSTS AND EXPENSES:
Lease operating expenses........................ 59,157 31,111
Exploration costs............................... 2,665 3,254
Depreciation, depletion and amortization........ 19,835 16,241
Loss on sale of assets, net..................... 329 ---
General and administrative expenses............. 7,276 8,705
Interest expense, net........................... 11,135 8,290
Dividends on Guaranteed Preferred
Beneficial Interests in Company's
Convertible Debentures (TECONS)............... 1,653 1,653
Other expense................................... 1,793 1,160
-------- -------
103,843 70,414
-------- -------
Income before income taxes....................... 16,086 1,091
Provision for income taxes....................... 6,483 440
-------- -------
NET INCOME....................................... $ 9,603 $ 651
======== =======
EARNINGS PER SHARE:
Basic:
Earnings per common share........................ $0.58 $0.04
======== =======
Weighted average common shares outstanding....... 16,533 17,673
======== =======
DILUTED:
Earnings per common share........................ $0.57 $0.04
======== =======
Weighted average common and dilutive potential
common shares outstanding........................ 17,003 18,068
======== =======
See accompanying notes to condensed consolidated financial statements.
4
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in Thousands)
Three Months Ended March 31,
----------------------------
2001 2000
-------- --------
CASH FLOWS FROM OPERATING
ACTIVITIES:
Net income................................................ $ 9,603 $ 651
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, depletion and amortization............. 19,835 16,241
Loss (gain) on sale of assets, net................... 329 (140)
Dry hole costs....................................... 1,482 (44)
Amortization of other costs.......................... 596 444
Deferred taxes....................................... 5,923 800
Appreciation of deferred compensation plan........... 73 432
Mark to market of liability management swap.......... --- 781
Other................................................ 508 33
-------- --------
38,349 19,198
Changes in assets and liabilities:
Accounts receivable................................... (14,380) 9,934
Accounts payable and accrued liabilities.............. 19,207 (10,297)
Other................................................. (11,766) (261)
-------- --------
NET CASH PROVIDED BY OPERATING ACTIVITIES................ 31,410 18,574
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties..................... (23,006) (12,223)
Acquisitions of oil and gas properties.................. (28,168) ---
Additions to gas plant and other facilities............. (654) (524)
-------- --------
NET CASH USED IN INVESTING ACTIVITIES..................... (51,828) (12,747)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings................................ --- 8,025
Payments of long-term debt.............................. (25) (10,398)
Debt issuance costs..................................... (97) ---
Treasury stock purchases................................ (2,085) (11,614)
Proceeds from issuance of common stock.................. --- 1,618
-------- --------
NET CASH USED IN FINANCING ACTIVITIES.................... (2,207) (12,369)
-------- --------
Net decrease in cash and cash equivalents................ (22,625) (6,542)
Cash and cash equivalents at beginning of period......... 39,447 10,288
-------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD............. $ 16,822 $ 3,746
======== ========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of amounts capitalized) $ 856 $ 1,769
Income taxes refunded $ (681) $ ---
See accompanying notes to condensed consolidated financial statements.
5
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 March 31, 2001 and December 31, 2000 and the
results of operations and changes in cash flows for the periods ended March
31, 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.
The Company adopted SFAS No. 133 on January 1, 2001. In accordance with the
current 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
(loss) 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 will be 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.
On the date the derivative contract is entered into, the Company designates
its derivative as either a hedge of fair value of a recognized asset or
liability ("fair value" hedge), as a hedge of the variability of cash flows
to be received ("cash-flow" hedge), or as a foreign currency cash flow hedge.
Changes in the fair value of a derivative that is highly effective as, and
that is designated and qualifies as, a fair-value hedge, along with the loss
or gain on the hedged asset or liability that is attributable to the hedged
risk (including losses or gains on firm commitments), are recorded in
current-period earnings. Changes in the fair value of a cash-flow hedge are
recorded in other comprehensive income (loss) until earnings are affected by
the variability of cash flows. All of the Company's derivative instruments
outstanding on January 1, 2001 were designated as cash-flow hedges.
The Company formally documents all relationships between hedging instruments
and hedged items, as well as its risk-management objective and strategy for
undertaking various hedge transactions. This process includes linking all
derivatives that are designated as cash-flow hedges to forecasted
transactions. The Company also formally assesses, both at the hedge's
inception and on an ongoing basis, whether the derivatives that are used in
hedging transactions are highly effective in offsetting changes in cash flows
of hedged transactions. When it is determined that a derivative is not
highly effective as a hedge or that it has ceased to be a highly effective
hedge, the Company discontinues hedge accounting prospectively.
When hedge accounting is discontinued because it is probable that a
forecasted transaction will not occur, the derivative will continue to be
carried on the balance sheet at its fair value, and gains and losses that
were
6
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
accumulated in other comprehensive income (loss) will be recognized in
earnings immediately. In all other situations in which hedge accounting is
discontinued, the derivative will be carried at its fair value on the balance
sheet, with changes in its fair value recognized in earnings prospectively.
At March 31, 2001, the Company had recorded $15.2 million (net of related tax
benefit of $10.3 million) of cumulative hedging losses in other comprehensive
loss, of which $16.9 million (based on March 31, 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
$21.5 million and $26.5 million in the first quarter of 2001 and 2000,
respectively. The portion of the Company's hedging transactions that was
ineffective was ($7,000) for the first quarter of 2001 and was recorded in
Interest and other income.
For 2001, the Company has entered into swap arrangements on 26,200 BOPD for
the second quarter at an average WTI price of $19.84 per Bbl, for the third
quarter on 20,000 BOPD at an average WTI price of $21.22 per Bbl, and for the
fourth quarter on 15,500 BOPD at an average WTI price of $22.95 per Bbl. On a
physical volume basis, these hedges cover 45% 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. For the
remainder of 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. For the three months ended March 31, 2000, the Company recorded an
unrealized loss of $781,000 related to the change in the fair value of the
Notes. This swap arrangement was settled in the third quarter of 2000.
COMPREHENSIVE INCOME (LOSS)
Comprehensive income (loss) includes net income (loss) 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 (loss) for
the first quarter of 2001 and 2000 was as follows:
2001 2000
------ -----
Net income $ 9,603 $ 651
Comprehensive loss (12,039) ---
Reclassification entry 12,822 ---
-------- -----
Total comprehensive income $ 10,386 $ 651
======== =====
INVENTORY VALUATION
Historically, 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
7
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed of", 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.
3. INDUSTRY SEGMENT INFORMATION
As of March 31, 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").
8
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
For the Three Months Ended March 31,
------------------------------------
2001 2000
-------- -------
Sales to unaffiliated customers:
Oil and gas - Domestic.................... $112,161 $59,549
Oil and gas - International............... 7,070 11,190
-------- -------
Total sales................................. 119,231 70,739
Gain on sale of assets, net............... --- 140
Other revenues............................ 698 626
-------- -------
Total revenues.............................. $119,929 $71,505
======== =======
Operating profit before income taxes:
Oil and gas - Domestic.................... $ 38,114 $17,879
Oil and gas - International............... (510) 2,761
-------- -------
37,604 20,640
Unallocated corporate expenses.............. 8,730 9,606
Interest expense............................ 11,135 8,290
Dividends on TECONS......................... 1,653 1,653
-------- -------
Income before income taxes................ $ 16,086 $ 1,091
======== =======
Depreciation, depletion and amortization:
Oil and gas - Domestic.................... $ 18,189 $13,705
Oil and gas - International............... 1,280 2,169
Other..................................... 366 367
-------- -------
$ 19,835 $16,241
======== =======
4. LONG-TERM DEBT
Long-term debt consists of the following (amounts in thousands):
March 31, December 31,
2001 2000
------------------- ------------------
9 3/8% Senior Subordinated Notes due 2010..................................... $150,000 $150,000
9 1/2% Senior Subordinated Notes due 2008..................................... 257,310 257,310
9 1/2% Senior Subordinated Notes due 2006..................................... 2,392 2,417
-------- --------
Total long-term debt...................................................... $409,702 $409,727
======== ========
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. The Company's
reconciliation is as follows:
For the Three Months Ended March 31,
-----------------------------------------------------------
2001 2000
------ ------
Income Shares Income Shares
------------- ------------- ------------ ------------
Earnings per Common share - Basic........................ $9,603 16,533 $651 17,673
Effect of dilutive securities:
Stock options............................................ --- 292 --- 395
Benefit Trust............................................ 48 178 --- ---
------ ------ ---- ------
Earnings per Common share - Diluted...................... $9,651 17,003 $651 18,068
====== ====== ==== ======
9
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
6. CONTINGENCIES AND OTHER MATTERS
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 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
plaintiff's allegation 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 plaintiff's 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.
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.
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 accrued $0.7 million as of
March 31, 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'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
10
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
Congo subsidiary, (ii) either Congo subsidiary's sale of its interest in the
Yombo field, (iii) the acquisition of 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 January 2001, the Company acquired approximately 2,900 acres previously
held by Naftex ARM, LLC, in Kern County, California. The Company paid
approximately $28.2 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 1,000 BOE per day, of which more
than half is natural gas. In addition, the acreage provides significant
development potential.
8. DIVESTITURES
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 $923,000.
9. SHARE REPURCHASES
Since December 1997, the Board of Directors of the Company has authorized the
open market repurchase of up to 4,616,600 shares of outstanding Common Stock
at times and at prices deemed appropriate by management and consistent with
the authorization of the Board. During the three months ended March 31, 2001,
the Company repurchased 127,800 shares at an average purchase price of $16.32
per share, including commissions. As of March 31, 2001, the Company had
repurchased 3,608,900 shares since December 1997, on a cumulative basis, at
an average purchase price of $16.56 per share, including commissions, under
the current share repurchase program.
11
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, including
without limitation, statements under "Management's Discussion and Analysis of
Financial Condition and Results of Operations" regarding the Company's
financial position, estimated quantities and net present values of reserves,
business strategy, plans and objectives of management of the Company for
future operations and covenant compliance, are forward-looking statements.
Although the Company believes that the assumptions upon which such forward-
looking statements are based are reasonable, it can give no assurances that
such assumptions will prove to have been correct. Important factors that
could cause actual results to differ materially from the Company's
expectations ("Cautionary Statements") are disclosed below and elsewhere in
this document and in the Company's Annual Report on Form 10-K and other
filings made with the Securities and Exchange Commission. All subsequent
written and oral forward-looking statements attributable to the Company or
persons acting on its behalf are expressly qualified by the Cautionary
Statements.
CAPITAL RESOURCES AND LIQUIDITY
Since inception, the Company has expanded its operations through a series of
disciplined, low-cost acquisitions of oil and gas properties and the
subsequent exploitation and development of these properties. The Company has
complemented these efforts with 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 $31.4 million and $18.6 million for the three months
ended March 31, 2001 and 2000, respectively. The Company invested $52.4
million (including acquisitions of $28.2 million) and $15.9 million in oil
and gas properties for the three months ended March 31, 2001 and 2000,
respectively.
The current borrowing base on the Company's credit facility is $225.0
million. At March 31, 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 March 31, 2001. At
March 31, 2001, the Company had a working capital deficit of $4.9 million.
Since December 1997, the Board of Directors of the Company has authorized the
open market repurchase of up to 4,616,600 shares of outstanding Common Stock
at times and at prices deemed appropriate by management and consistent with
the authorization of the Board. During the three months ended March 31, 2001,
the Company repurchased 127,800 shares at an average purchase price of $16.32
per share, including commissions. As of March 31, 2001, the Company had
repurchased 3,608,900 shares since December 1997, on a cumulative basis, at
an average purchase price of $16.56 per share, including commissions, under
the current share repurchase program.
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
The Company anticipates spending an additional $100.0 million on development
activities and an additional $36.0 million on exploration activities and
other capital projects during the remainder of the year.
12
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Exploration and development expenditures, including acquisitions and amounts
expensed under the successful efforts method, for the first three months of
2001 and 2000 are as follows (amounts in thousands):
For the Three Months Ended
March 31,
-----------------------------
2001 2000
------- -------
Domestic $44,578 $12,400
International 7,772 3,506
------- -------
Total $52,350 $15,906
======= =======
The following is a description of significant exploration and development
activity during the first three months of 2001.
Exploration Activity
Domestic
As part of its strategy to explore for deeper, larger prospects and lighter
hydrocarbons onshore California, in January 2001 the Company acquired
approximately 2,900 acres previously held by Naftex ARM, LLC, in Kern County,
California for approximately $28.2 million. The newly acquired acreage is
southeast of Nuevo's deep Point of Rocks discovery, the Star Fee 701 well.
While there is considerable exploration potential in this acreage, it has the
additional benefit of current production of approximately 1,000 BOE per day,
of which more than half is natural gas. In addition, the acreage provides
significant development potential.
The Star Fee 701 well has produced more than 200,000 BOE since mid-August
2000. The Star Fee 701 well is currently producing approximately 500 BOE per
day, consisting of 30 API oil and just under 1 million cubic feet per day of
associated gas, from a single sand package within the Point of Rocks
formation. This discovery well was drilled to a total depth of 11,200 feet
and penetrated four Point of Rocks sand packages. Total net pay from the
upper two sand packages is approximately 500 feet. The production capability
of the two lower zones is currently unknown. The Company plans to target
these deeper sand packages for completion in an offset well in the near
future. In addition, Nuevo plans to drill at least two deep prospects in the
newly acquired acreage in 2001.
Nuevo also drilled a shallow gas discovery, the Golden 1-21 well, in Kern
County, California. This well was drilled to a total depth of 6,055 feet and
initially produced at a rate of approximately 1 MMcfd. The Golden 1-21 well
is currently producing at a rate of approximately 500 Mcfd. Nuevo is
applying for permits to drill six delineation wells starting in the summer
2001. The Golden 1-21 discovery well is located approximately four miles
from the South Belridge and Elk Hills Fields. Nuevo is the operator of the
30,000-acre Area of Mutual Interest in which the Golden 1-21 well is located
and holds an 86% interest in the well.
International
During January and February 2001, Nuevo drilled the NAK #1 exploratory well
in the Accra-Keta Permit, offshore the Republic of Ghana. This well was
located in approximately 1,000 feet of water and was drilled to a total depth
of 10,100 feet. The Company plugged and abandoned the NAK #1 well as a dry
hole. Costs to drill this well were approximately $12.5 million
(approximately $1.5 million net to Nuevo), and were incurred in the first
quarter of 2001. The Company plans to evaluate the NAK #1 well results
during the second quarter of 2001 in order to determine its future
exploration plans in this permit.
13
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Development Activity
Domestic
Due to the current high gas prices in California, Nuevo deferred certain
capital spending associated with its thermal operations, assuming gas prices
remain at these high levels for the remainder of the year.
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 quarter of 2001, this development included drilling 17 Diatomite
development wells and one follow-up well to the highly successful Star Fee
701 well. This Star Fee 702 well is currently being drilled, and results
should be evaluated in the second quarter of 2001.
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 $2.0 million, $1.7 million of which
was capitalized in the first quarter. In addition, three wells were drilled
on the B Platform as part of a five-well drilling program. These wells have
been completed and are currently producing at a combined rate of
approximately 2,400 BOPD. The remaining two wells in this program will
commence drilling in 2001.
CALIFORNIA NATURAL GAS AND ELECTRICITY MARKETS
The price of natural gas and the threat of electrical disruptions are factors
that create volatility in the Company's 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
prices escalated in late 2000, Nuevo began to exploit this gas position by
diverting gas consumed in less profitable cyclic steaming operations to more
profitable gas sales. This strategy will remain as long as gas prices support
sales over thermal oil production.
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 using gas previously flared. Three turbines in Kern County can produce
12 MW of power and cogenerate 15% of Nuevo's total steam needs in thermal
operations. By self-generating power consumption in Kern County, Nuevo has
reduced it exposure to rising electricity prices. Nuevo's facilities receive
power under interruptible service contracts. Considering the fact that
California is short of electricity and some Nuevo facilities receive
interruptible service, the Company 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.
The Company adopted SFAS No. 133 on January 1, 2001. In accordance with the
current 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
(loss) 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 will be 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.
14
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
On the date the derivative contract is entered into, the Company designates
its derivative as either a hedge of fair value of a recognized asset or
liability ("fair value" hedge), as a hedge of the variability of cash flows
to be received ("cash-flow" hedge), or as a foreign currency cash flow hedge.
Changes in the fair value of a derivative that is highly effective as, and
that is designated and qualifies as, a fair-value hedge, along with the loss
or gain on the hedged asset or liability that is attributable to the hedged
risk (including losses or gains on firm commitments), are recorded in
current-period earnings. Changes in the fair value of a cash-flow hedge are
recorded in other comprehensive income (loss) until earnings are affected by
the variability of cash flows. All of the Company's derivative instruments
outstanding on January 1, 2001 were designated as cash-flow hedges.
The Company formally documents all relationships between hedging instruments
and hedged items, as well as its risk-management objective and strategy for
undertaking various hedge transactions. This process includes linking all
derivatives that are designated as cash-flow hedges to forecasted
transactions. The Company also formally assesses, both at the hedge's
inception and on an ongoing basis, whether the derivatives that are used in
hedging transactions are highly effective in offsetting changes in cash flows
of hedged transactions. When it is determined that a derivative is not
highly effective as a hedge or that it has ceased to be a highly effective
hedge, the Company discontinues hedge accounting prospectively.
When hedge accounting is discontinued because it is probable that a
forecasted transaction will not occur, the derivative will continue to be
carried on the balance sheet at its fair value, and gains and losses that
were accumulated in other comprehensive income (loss) will be recognized in
earnings immediately. In all other situations in which hedge accounting is
discontinued, the derivative will be carried at its fair value on the balance
sheet, with changes in its fair value recognized in earnings prospectively.
At March 31, 2001, the Company had recorded $15.2 million (net of related tax
benefit of $10.3 million) of cumulative hedging losses in other comprehensive
loss, of which $16.9 million (based on March 31, 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
$21.5 million and $26.5 million in the first quarter of 2001 and 2000,
respectively. The portion of the Company's hedging transactions that was
ineffective was ($7,000) for the first quarter of 2001 and was recorded in
Interest and other income.
For 2001, the Company has entered into swap arrangements on 26,200 BOPD for
the second quarter at an average WTI price of $19.84 per Bbl, for the third
quarter on 20,000 BOPD at an average WTI price of $21.22 per Bbl, and for the
fourth quarter on 15,500 BOPD at an average WTI price of $22.95 per Bbl. On a
physical volume basis, these hedges cover 45% 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. For the
remainder of 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. For the three months ended March 31, 2000, the Company recorded an
unrealized loss of $781,000 related to the change in the fair value of the
Notes. This swap arrangement was settled in the third quarter of 2000.
15
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
SUBSEQUENT EVENT
On May 8, 2001, the Board of Directors of the Company announced that it accepted
the resignation of Douglas L. Foshee as Chairman, President and Chief Executive
Officer of the Company, effectively immediately. The Board announced that Isaac
Arnold, an outside Nuevo director since 1990, was appointed Chairman of the
Board. The Board also announced that Phillip Gobe, currently Nuevo's Chief
Operating Officer, was appointed President and Chief Executive Officer on an
interim basis. The Nominating and Governance Committee has initiated a search
for a new President and Chief Executive Officer, and Mr. Gobe will be considered
as part of this search.
RESULTS OF OPERATIONS (THREE MONTHS ENDED MARCH 31, 2001 AND 2000)
The following table sets forth certain operating information of the Company
(inclusive of the effect of hedging) for the periods presented:
Three Months
Ended March 31, %
------------------ Increase/
2001 2000 (Decrease)
------ ------ ---------
PRODUCTION:
Oil and condensate - Domestic (MBBLS)..................... 3,892 3,714 5%
Oil and condensate - International (MBBLS)................ 252 501 (50%)
------ ------
Oil and condensate - Total (MBBLS)........................ 4,144 4,215 (2%)
Natural gas - Domestic/Total (MMCF)....................... 3,824 3,995 (4%)
Natural gas liquids - Domestic/Total (MBBLS).............. 44 41 7%
Equivalent barrels of production - Domestic (MBOE)........ 4,573 4,421 3%
Equivalent barrels of production - International (MBOE)... 252 501 (50%)
------ ------
Equivalent barrels of production - Total (MBOE)........... 4,825 4,922 (2%)
AVERAGE SALES PRICE:
Oil and condensate (per Bbl):
Domestic - net of hedge effect............................ $15.45 $13.13 18%
International - net of hedge effect and Congo earn-out.... $28.01 $22.32 25%
Total - exclusive of hedges and Congo earn-out............ $21.65 $20.52 6%
Total - hedge effect and Congo earn-out................... $(5.44) $(6.30) 14%
------ ------
Total - net of hedge effect and Congo earn-out............ $16.21 $14.22 14%
====== ======
Natural gas - Domestic/Total.............................. $13.26 $ 2.42 448%
LEASE OPERATING EXPENSE:
Average unit production cost(1) per BOE - Domestic........ $12.01 $ 6.28 91%
Average unit production cost(1) per BOE - International... $16.87 $ 6.69 152%
Average unit production cost(1) per BOE - Total........... $12.26 $ 6.32 94%
(1) Costs incurred to operate and maintain wells and related equipment and
facilities, including ad valorem and severance taxes.
16
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Revenues
Oil and Gas Revenues:
Oil and gas revenues for the three months ended March 31, 2001, were $119.2
million, or 69% higher than oil and gas revenues for the same period in 2000.
This increase is primarily due to a significant increase in realized gas prices
(from $2.42 per Mcf to $13.26 per Mcf, quarter over quarter) and a 14% increase
in realized oil prices. These increases were partially offset by a slight
decrease in production, which was primarily attributable to a decrease in
international oil production that resulted from two pipeline replacements in the
first quarter of 2001. First quarter 2001 oil price realizations reflect hedging
losses of $21.5 million, or $5.18 per barrel. First quarter 2000 oil price
realizations reflect hedging losses of $26.5 million, or $6.29 per barrel.
Domestic: Oil and gas revenues for the three months ended March 31, 2001, were
$112.2 million, or 88% higher than oil and gas revenues for the same period in
2000. This increase is primarily due to a 448% improvement in average realized
gas prices and an 18% improvement in average realized oil prices (net of
hedges), further boosted by a 3% increase in total production. The realized oil
price of $15.45 per barrel for the first quarter of 2001 includes negative
hedging results of $5.52 per domestic barrel of oil. The realized oil price of
$13.13 per barrel for the first quarter of 2000 includes negative hedging
results of $7.50 per domestic barrel of oil.
International: Oil revenues for the three months ended March 31, 2001,
decreased $4.1 million, or 37%, compared to the same period in 2000. This
decrease resulted from a 50% decrease in oil production that resulted from the
temporary shut-down of production while two pipelines were replaced in the Congo
during the first quarter of 2001. This decrease in production was partially
offset by a 25% increase in oil price realizations to $28.01 per barrel. The
realized oil price for the first quarter of 2000 includes hedging gains of $2.70
per international barrel of oil. There were no hedges in place for the first
quarter of 2001 for international production.
Interest and Other Income:
The 12% increase in interest and other income in the first quarter of 2001 as
compared to the same period in 2000 is primarily due to higher interest income
that resulted from higher average cash balances in 2001.
Expenses
Lease Operating Expenses:
Lease operating expenses for the three months ended March 31, 2001, were $59.2
million, or 90% higher than for the three months ended March 31, 2000. The
majority of this increase is due to a $21.4 million increase in steam costs
related to the Company's thermal oil producing operations. Additionally, there
was a $2.0 million increase in turbine fuel costs at the Company's Brea Olinda
field onshore California. The Brea Olinda facilities came on-line after the
first quarter of 2000, so all associated costs are additive in the first quarter
of 2001. Lease operating expenses per BOE were $12.26 in the first quarter of
2001, compared to $6.32 in the same period in 2000.
Domestic: Lease operating expenses per BOE were $12.01 in the first quarter of
2001, compared to $6.28 in the same period in 2000. Higher steam and facility
costs contributed to the higher lease operating expenses quarter over quarter.
International: Lease operating expenses per BOE were $16.87 in the first
quarter of 2001, compared to $6.69 in the same period in 2000. The significant
increase in lease operating expenses per BOE is primarily attributable to the
50% decrease in production.
17
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Exploration Costs:
Exploration costs, including geological and geophysical ("G&G") costs, dry hole
costs, delay rentals and expensed project costs, were $2.7 million and $3.3
million for the three months ended March 31, 2001 and 2000, respectively. For
the three months ended March 31, 2001, exploration costs were comprised of $1.5
million of dry hole costs (related to the NAK #1 exploratory well in the Accra-
Keta Permit, offshore the Republic of Ghana), $1.0 million in G&G, and $0.2
million of other project costs. For the three months ended March 31, 2000,
exploration costs were comprised of $3.2 million in G&G (primarily for 3-D
seismic acquisition and processing in the Accra-Keta prospect, offshore the
Republic of Ghana), and $0.1 million in delay rentals.
Depreciation, Depletion and Amortization:
Depreciation, depletion and amortization for the three months ended March 31,
2001, reflects a 22% increase from the same period in 2000, due to a higher
depletion rate, which primarily resulted from a decrease in reserve estimates at
year-end 2000 versus year-end 1999. The decrease in reserve estimates was 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.
(Loss) Gain on Sale of Assets, net:
Loss on sale of assets for the three months ended March 31, 2001, was $329,000,
representing subsequent sales price adjustments relating to the Company's sale
of certain oil and gas properties in 2000. Gain on sale of assets for the three
months ended March 31, 2000, was $140,000, representing subsequent sales price
adjustments relating to the Company's sale of certain oil and gas properties in
1999.
General and Administrative Expenses:
General and administrative expenses were $7.3 million and $8.7 million in the
three months ended March 31, 2001 and 2000, respectively. The 16% decrease is
due primarily to a $0.5 million decrease in salaries and benefits and a $0.4
million lower mark to market effect on the liabilities associated with the
Company's deferred compensation plan. The remaining decrease is made up of
individually insignificant items.
Interest Expense:
Interest expense of $11.1 million for the three months ended March 31, 2001,
increased 34% 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 third quarter of 2000, partially offset by a decrease in
outstanding borrowings on the Company's credit facility.
Other Expense:
The 55% increase in other expense from the first quarter of 2000 to the first
quarter of 2001 is primarily due to the impairment of $1.4 million of
electricity receivables in the first quarter of 2001. This increase was
partially offset by a mark to market adjustment of $781,000 related to the
Company's liability management swap (see Note 1 to the Notes to Condensed
Consolidated Financial Statements) in the first quarter of 2000.
Net Income
Net income of $9.6 million, $0.58 per common share - basic and $0.57 per common
share - diluted, was reported for the three months ended March 31, 2001, as
compared to net income of $651,000, $0.04 per common share - basic and diluted,
reported for the same period in 2000.
18
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.
19
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, 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,
incurred operating expenses, nor booked any proved reserves 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
None.
(B) REPORTS ON FORM 8-K.
1) A Current Report on Form 8-K, dated January 12, 2001, reporting Item
9. Regulation FD Disclosure was filed on January 12, 2001.
2) A Current Report on Form 8-K, dated February 8, 2001, reporting Item
9. Regulation FD Disclosure was filed on February 8, 2001.
3) A Current Report on Form 8-K, dated March 14, 2001, reporting Item
4. Change in Registrant's Certifying Accountant was filed on March
14, 2001.
4) A Current Report on Form 8-K, dated March 16, 2001, reporting Item
9. Regulation FD Disclosure was filed on March 16, 2001.
20
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.
. BOPD -- One barrel of oil per day.
. 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.
. MMcfd-- One million cubic feet of natural gas per day.
. 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
21
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.
. 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.
. Net revenue 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, net of royalty
interests and costs to explore for, develop and produce such oil and
natural gas.
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 than 2-D seismic data.
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.
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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: May 15, 2001 By: /s/ Robert M. King
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Robert M. King
Senior Vice President and Chief Financial
Officer (Principal Financial Officer)
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