UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (D)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 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 August 8, 2001, the number of outstanding shares of the Registrant's
common stock was 16,989,326.
NUEVO ENERGY COMPANY
INDEX
PART I. FINANCIAL INFORMATION
PAGE
NUMBER
ITEM 1. Financial Statements
Condensed Consolidated Balance Sheets:
June 30, 2001 (Unaudited) and December 31, 2000................... 3
Condensed Consolidated Statements of Operations (Unaudited):
Three and six months ended June 30, 2001 and June 30, 2000........ 4
Condensed Consolidated Statements of Cash Flows (Unaudited):
Six months ended June 30, 2001 and June 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. 25
PART II. OTHER INFORMATION......................................... 26
2
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Amounts in Thousands, Except Share Data)
June 30, 2001 December 31, 2000
-------------- ------------------
ASSETS (Unaudited)
------
CURRENT ASSETS:
Cash and cash equivalents.................................................................... $ 3,092 $ 39,447
Accounts receivable, net..................................................................... 69,026 71,777
Product inventory............................................................................ 3,827 3,230
Prepaid expenses and other................................................................... 12,491 4,042
---------- ----------
Total current assets....................................................................... 88,436 118,496
---------- ----------
PROPERTY AND EQUIPMENT, AT COST:
Land......................................................................................... 58,266 53,246
Oil and gas properties (successful efforts method)........................................... 1,202,028 1,102,233
Gas plant facilities......................................................................... 8,723 12,020
Other facilities............................................................................. 13,519 12,907
---------- ----------
1,282,536 1,180,406
Accumulated depreciation, depletion and amortization......................................... (537,853) (496,444)
---------- ----------
744,683 683,962
---------- ----------
DEFERRED TAX ASSETS, NET...................................................................... 8,875 16,282
OTHER ASSETS.................................................................................. 42,191 29,284
---------- ----------
$ 884,185 $ 848,024
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
CURRENT LIABILITIES:
Accounts payable............................................................................ $ 25,736 $ 25,895
Accrued interest............................................................................ 5,561 5,757
Accrued drilling costs...................................................................... 16,308 12,467
Accrued lease operating costs............................................................... 44,580 30,037
Other accrued liabilities................................................................... 27,978 17,668
---------- ----------
Total current liabilities............................................................... 120,163 91,824
---------- ----------
LONG-TERM DEBT, NET OF CURRENT MATURITIES..................................................... 409,702 409,727
OTHER LONG-TERM LIABILITIES................................................................... 7,238 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, 20,900,921 and 20,620,296
shares issued and 16,875,205 and 16,632,318 shares outstanding at June 30, 2001 and
December 31, 2000, respectively............................................................ 209 206
Additional paid-in capital.................................................................. 366,028 361,643
Treasury stock, at cost, 3,912,949 and 3,813,074 shares, at
June 30, 2001 and December 31, 2000, respectively........................................ (76,333) (74,703)
Stock held by benefit trust, 112,767 and 174,904 shares, at
June 30, 2001 and December 31, 2000, respectively........................................ (2,690) (3,646)
Deferred stock compensation................................................................. (453) (602)
Other comprehensive loss.................................................................... (7,160) ---
Accumulated deficit......................................................................... (47,519) (59,781)
---------- ----------
Total stockholders' equity.............................................................. 232,082 223,117
---------- ----------
$ 884,185 $ 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 June 30,
---------------------------
2001 2000
-------- -------
REVENUES:
Oil and gas revenues............................ $100,260 $69,136
Gain on sale of assets, net..................... 198 366
Interest and other income....................... 241 195
-------- -------
100,699 69,697
-------- -------
COSTS AND EXPENSES:
Lease operating expenses........................ 49,038 33,896
Exploration costs............................... 5,382 1,488
Depreciation, depletion and amortization........ 20,398 15,164
General and administrative expenses............. 9,229 7,531
Interest expense, net........................... 10,449 8,517
Dividends on Guaranteed Preferred
Beneficial Interests in Company's
Convertible Debentures (TECONS)............... 1,653 1,653
Other expense................................... 99 2,687
-------- -------
96,248 70,936
-------- -------
Income (loss) before income taxes................ 4,451 (1,239)
Provision (benefit) for income taxes............. 1,792 (499)
-------- -------
NET INCOME (LOSS)................................ $ 2,659 $ (740)
======== =======
EARNINGS (LOSS) PER SHARE:
Basic:
Earnings (loss) per common share................. $0.16 $(0.04)
======== =======
Weighted average common shares outstanding....... 16,645 17,429
======== =======
DILUTED:
Earnings (loss) per common share................. $0.14 $(0.04)
======== =======
Weighted average common and dilutive potential
common shares outstanding........................ 17,152 17,429
======== =======
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)
Six Months Ended June 30,
-------------------------
2001 2000
-------- --------
REVENUES:
Oil and gas revenues.................................................. $217,406 $139,357
Gain (loss) on sale of assets, net.................................... (131) 506
Interest and other income............................................. 946 821
-------- --------
218,221 140,684
-------- --------
COSTS AND EXPENSES:
Lease operating expenses.............................................. 106,325 65,083
Exploration costs..................................................... 8,047 4,742
Depreciation, depletion and amortization.............................. 40,025 31,391
General and administrative expenses................................... 16,505 16,236
Interest expense, net................................................. 21,584 16,807
Dividends on Guaranteed Preferred
Beneficial Interests in Company's
Convertible Debentures (TECONS)..................................... 3,306 3,306
Other expense......................................................... 1,892 3,847
-------- --------
197,684 141,412
-------- --------
Income (loss) before income taxes and cumulative effect................ 20,537 (728)
Provision (benefit) for income taxes................................... 8,275 (293)
-------- --------
Income (loss) before cumulative effect................................. 12,262 (435)
Cumulative effect of a change in accounting principle, net of income
tax benefit of $537................................................... --- (796)
-------- --------
NET INCOME (LOSS)...................................................... $ 12,262 $ (1,231)
======== ========
EARNINGS (LOSS) PER SHARE:
Basic:
Income (loss) before cumulative effect................................ $ 0.74 $ (0.02)
Cumulative effect of a change in accounting principle,
net of income tax benefit........................................... --- (0.05)
-------- --------
Earnings (loss) per common share...................................... $ 0.74 $ (0.07)
======== ========
Weighted average common shares outstanding............................. 16,589 17,551
======== ========
DILUTED:
Income (loss) before cumulative effect................................ $ 0.71 $ (0.02)
Cumulative effect of a change in accounting principle,
net of income tax benefit........................................... --- (0.05)
-------- --------
Earnings (loss) per common share...................................... $ 0.71 $ (0.07)
======== ========
Weighted average common and dilutive potential
common shares outstanding.............................................. 17,078 17,551
======== ========
See accompanying notes to condensed consolidated financial statements.
5
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in Thousands)
Six Months June 30,
-------------------
2001 2000
-------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss).................................. $ 12,262 $ (1,231)
Adjustments to reconcile net income (loss) to
net cash provided by/(used in) operating
activities:
Depreciation, depletion and amortization...... 40,025 31,391
Cumulative effect of a change in accounting
principle, net of income tax benefit......... --- 796
Loss (gain) on sale of assets, net............ 131 (506)
Dry hole costs................................ 1,986 89
Impairment of oil and gas properties.......... 880 ---
Amortization of other costs................... 1,195 903
Deferred taxes................................ 8,175 78
Other......................................... 319 461
-------- --------
64,973 31,981
Changes in assets and liabilities:...............
Accounts........................................ 1,540 8,450
Accounts........................................ 19,562 (3,152)
Other........................................... (19,724) (951)
-------- --------
NET CASH PROVIDED BY OPERATING ACTIVITIES.......... 66,351 36,328
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties............. (70,035) (43,609)
Acquisitions of oil and gas properties.......... (28,456) ---
Additions to gas plant facilities............... --- (126)
Additions to other facilities................... (5,631) (721)
Proceeds from sales of properties............... --- 1,297
-------- --------
NET CASH (USED IN) INVESTING ACTIVITIES............ (104,122) (43,159)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings......................... 54,950 32,500
Deferred financing costs......................... (97) (1,634)
Payments of long-term debt....................... (54,975) (10,773)
Treasury stock purchases......................... (2,085) (12,540)
Proceeds from issuance of common stock........... 3,623 2,112
-------- --------
NET CASH PROVIDED BY FINANCING ACTIVITIES........... 1,416 9,665
-------- --------
Net (decrease) increase in cash and cash
equivalents..................................... (36,355) 2,834
Cash and cash equivalents at beginning of period. 39,447 10,288
-------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD.......... $ 3,092 $ 13,122
======== ========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of amounts capitalized)............ $20,244 $15,782
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 June 30, 2001 and December 31, 2000 and the
results of operations and changes in cash flows for the periods ended June
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.
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 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 June 30, 2001, the Company had recorded $7.2 million (net of related tax
benefit of $4.8 million) of cumulative hedging losses in other comprehensive
loss, of which $6.4 million (based on June 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
$40.9 million and $51.3 million in the first six months of 2001 and 2000,
respectively. The portion of the Company's hedging transactions that was
ineffective was $3,000 for the first six 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 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 39% 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. 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 six months ended June 30, 2000, the Company recorded an
unrealized loss of $371,000 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 six months of 2001 and 2000 was as follows:
2001 2000
-------- --------
Net income (loss) $ 12,262 $(1,231)
Comprehensive loss (15,584) ---
Reclassification entry 24,399 ---
-------- -------
Total comprehensive income (loss) $ 21,077 $(1,231)
======== =======
RECENT ACCOUNTING PRONOUNCEMENTS
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. Over time, accretion of the liability is
recognized each period, and the capitalized cost is depreciated 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 Statement No. 143 on
its financial statements and has not determined the timing of adoption.
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.
8
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
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.
9
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
3. INDUSTRY SEGMENT INFORMATION
As of June 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 Six Months Ended June 30,
---------------------------------
2001 2000
-------- --------
(amounts in thousands)
Sales to unaffiliated customers:
Oil and gas - Domestic..................... $204,123 $121,354
Oil and gas - International................ 13,283 18,003
-------- --------
Total sales................................. 217,406 139,357
Gain (loss) on sale of assets, net......... (131) 506
Other revenues............................. 946 821
-------- --------
Total revenues.............................. $218,221 $140,684
======== ========
Operating profit before income taxes:
Oil and gas - Domestic..................... $ 58,816 $ 35,399
Oil and gas - International................ 4,193 2,742
-------- --------
63,009 38,141
Unallocated corporate expenses.............. 17,582 18,756
Interest expense, net....................... 21,584 16,807
Dividends on TECONS......................... 3,306 3,306
-------- --------
Income (loss) before income taxes.......... $ 20,537 $ (728)
======== ========
Depreciation, depletion and amortization:
Oil and gas - Domestic..................... $ 35,416 $ 26,854
Oil and gas - International................ 3,466 3,804
Other...................................... 1,143 733
-------- --------
$ 40,025 $ 31,391
======== ========
4. LONG-TERM DEBT
Long-term debt consists of the following (amounts in thousands):
June 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.................................... 257,310 257,310
9 1/2% Senior Subordinated Notes due 2006.................................... 2,392 2,417
------------------- ------------------
Total long-term debt...................................................... $409,702 $409,727
=================== ==================
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. The Company's
reconciliation is as follows:
For the Three months Ended June 30,
------------------------------------------------------------
2001 2000
------------------------------ ----------------------------
Income Shares (Loss) Shares
------------- ------------- ------------ ------------
Earnings (loss) per Common share - Basic................. $2,659 16,645 $(740) 17,429
Effect of dilutive securities:
Stock options.......................................... --- 338 --- ---
Benefit Trust.......................................... (217) 169 --- ---
------ ------ ----- ------
Earnings (loss) per Common share - Diluted............... $2,442 17,152 $(740) 17,429
====== ====== ===== ======
For the Six months Ended June 30,
-------------------------------------------------------------
2001 2000
------------------------------ ----------------------------
Income Shares (Loss) Shares
------------- ------------- ------------ ------------
Earnings (loss) before cumulative effect
per Common share - Basic............................... $12,262 16,589 $ (435) 17,551
Effect of dilutive securities:
Stock options......................................... --- 316 --- ---
Benefit Trust......................................... (170) 173 --- ---
------- ------ ------- ------
Earnings (loss) before cumulative effect per Common
share - Diluted........................................ $12,092 17,078 $ (435) 17,551
======= ====== ======= ======
Certain of the Company's stock options that would potentially dilute Basic
EPS in the future were not included in the computation of Diluted EPS because
to do so would have been antidilutive for the three and six months ended June
30, 2000.
6. CONTINGENCIES AND OTHER MATTERS
On June 15, 2001, the Company experienced a failure of a carbon dioxide
treatment vessel at the Rincon Offshore 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. As of early July, the crude oil production resumed and efforts
are underway to bring the natural gas production back online. The cost of
repair less a $20,000 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.
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 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.
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
11
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
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 June 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 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.
12
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
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 800 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
$0.9 million was recorded during the second quarter 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 of
outstanding Common Stock 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 quarter of 2001. As of June 30, 2001,
the Company has 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.
13
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
ITEM 2.
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 $65.1 million and $36.3 million for the six months
ended June 30, 2001 and 2000, respectively. The Company invested $104.1
million (including acquisitions of $28.5 million) and $43.2 million in oil
and gas properties for the six months ended June 30, 2001 and 2000,
respectively.
The current borrowing base on the Company's credit facility is $225.0
million. At June 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 June 30, 2001. At June
30, 2001, the Company had a working capital deficit of $31.7 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 of
outstanding Common Stock 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 quarter of 2001. As of June 30, 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.
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 $65.0 million on development
activities and an additional $18.0 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 six months of
2001 and 2000 are as follows (amounts in thousands):
For the Six Months Ended
June 30,
--------------------------
2001 2000
---------- -------
Domestic $ 92,663 $44,063
International 14,297 4,515
-------- -------
Total $106,960 $48,578
======== =======
The following is a description of significant exploration and development
activity during the first six 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 $28.5 million. The newly acquired acreage is
southeast of Nuevo's deep Point of Rocks ("POR") 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 800 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 250,000 BOE since mid-August
2000. The Star Fee 701 well is currently producing approximately 260 BOE per
day, consisting of 30 API oil and just under 400 thousand cubic feet per day
of associated gas, from a single sand package within the POR formation. This
discovery well was drilled to a total depth of 11,200 feet and penetrated
four POR 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.
In June, Nuevo spud its second POR prospect, Cutthroat. The Cutthroat
exploratory well will be drilled to a total depth of 14,000 feet and is
designed to test five zones within the POR formation. The Cutthroat prospect
is located on acreage acquired from Naftex ARM, LLC, in Kern County. During
the second quarter, Nuevo acquired almost 100 miles of 2D seismic and
purchased approximately 23 square miles of 3D seismic data in southern Kern
County to better delineate the deep Star Fee structure and to help identify
new opportunities within the POR trend.
Two shallow Stevens Sand prospects, Moneypenny and Doubleshot, were drilled
during the second quarter in the Buena Vista Hills area. Both wells were dry
holes and Nuevo held a 30% working interest in each prospect. Net dry hole
costs to Nuevo totaled about $375,000 for both wells.
During the first quarter of 2001, Nuevo drilled a shallow gas discovery, the
Golden 1-21 well, in Kern County California. This well was drilled to a
total depth of 6,050 feet and initially produced at a rate of approximately 1
MMcfd. The Golden 1-21 well produced cumulative production of 32 MMcf.
After an unsuccessful workover, the productive interval was found to be
depleted, and the well will be plugged and abandoned.
15
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Six exploration wells will spud in California in July and August. These
include two Temblor Formation tests, Thunderball and Steelhead, two shallow
gas wells, Brook and a follow-up to the Golden 1-21, and one Stevens Channel
test, Goldeneye.
International
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
scheduled to be drilled in the Anaguid Permit during the fourth quarter 2001.
During the past several years Nuevo has built a 2.2 million-acre portfolio of
assets onshore and offshore Tunisia which includes the Anaguid Permit as well
as two additional permits. Nuevo has a 100% interest and is operator of the
171,000-acre Alyane Permit located offshore Tunisia in the Gulf of Gabes.
Nuevo also has a 42.8% non-operated interest in the 900,000-acre Fejaj Permit
onshore Tunisia.
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. 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 and expensed in the first quarter of
2001.
Development Activity
Domestic
Due to recent high gas prices in California, Nuevo has deferred certain
capital spending associated with its thermal operations, assuming gas prices
remain at these high levels for the remainder of the year. The Company is
currently evaluating its plans after the recent reduction in California gas
prices.
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 six months of 2001, this development included drilling 20
Diatomite development wells and one follow-up well to the highly successful
Star Fee 701 well. The Star Fee 702 well is currently being completed and
results should be reported in the third 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 $5.0 million. In addition, three
wells were drilled on the B Platform and one well 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 4,000 BOPD. The
remaining well in this program will be completed in July 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 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
16
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
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. 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 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 June 30, 2001, the Company had recorded $7.2 million (net of related tax
benefit of $4.8 million) of cumulative hedging losses in other comprehensive
loss, of which $6.4 million (based on June 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
$40.9 million and $51.3 million in the first six months of 2001 and 2000,
respectively. The portion of the Company's hedging transactions that was
ineffective was $3,000 for the first six 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 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 39% 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
17
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
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 six months ended June 30, 2000, the Company
recorded an unrealized loss of $371,000 related to the change in the fair
value of the Notes. This swap arrangement was settled in the third quarter of
2000.
RECENT ACCOUNTING PRONOUNCEMENTS
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. Over time, accretion of the liability is
recognized each period, and the capitalized cost is depreciated 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 Statement No. 143 on
its financial statements and has not determined the timing of adoption.
18
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
RESULTS OF OPERATIONS (THREE MONTHS ENDED JUNE 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 June 30, %
--------------- Increase/
2001 2000 (Decrease)
------ ------ ---------
PRODUCTION:
Oil and condensate - Domestic (MBBLS)..................... 3,687 3,640 1%
Oil and condensate - International (MBBLS)................ 532 477 12%
------ ------
Oil and condensate - Total (MBBLS)........................ 4,219 4,117 2%
Natural gas - Domestic (MMCF)............................. 2,959 3,816 (22%)
Natural gas liquids - Domestic (MBBLS).................... 51 44 16%
Equivalent barrels of production - Domestic (MBOE)........ 4,231 4,320 (2%)
Equivalent barrels of production - International (MBOE)... 532 477 12%
------ ------
Equivalent barrels of production - Total (MBOE)........... 4,763 4,797 (1%)
AVERAGE SALES PRICE:
Oil and condensate - Domestic............................. $15.32 $13.12 17%
Oil and condensate - International........................ $16.32 $15.37 6%
Oil and condensate - Total................................ $15.44 $13.39 15%
Natural gas - Domestic.................................... $11.45 $ 3.43 234%
LEASE OPERATING EXPENSE:
Average unit production cost(1) per BOE - Domestic........ $10.95 $ 7.12 54%
Average unit production cost(1) per BOE - International... $ 5.06 $ 6.58 (23%)
Average unit production cost(1) per BOE - Total........... $10.30 $ 7.07 46%
(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 June 30, 2001, were $100.3
million, or 45% higher than oil and gas revenues for the same period in 2000.
This increase is primarily due to a 15% increase in realized oil prices and a
234% increase in realized gas prices. Second quarter 2001 oil price realizations
reflect hedging losses of $19.4 million, or $4.60 per barrel compared with
hedging losses of $24.8 million, or $6.03 per barrel in the second quarter of
2000.
Domestic: Oil and gas revenues for the three months ended June 30, 2001, were
48% higher than oil and gas revenues for the same period in 2000. This increase
is primarily due to a 17% improvement in average realized oil prices and a 234%
improvement in average realized gas prices, slightly offset by a 2% decrease in
total production. The realized oil price of $15.32 per barrel for the second
quarter of 2001 includes negative hedging results of $5.26 per barrel of oil
compared with a realized oil price of $13.12 per barrel for the second quarter
of 2000, which includes negative hedging results of $6.81 per barrel of oil.
19
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
International: Oil revenues for the three months ended June 30, 2001, increased
18% 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 second quarter of 2001 relating to international production. The
realized oil price for the second quarter of 2000 includes hedging gains of
$1.44 per barrel of oil.
Expenses
Lease Operating Expenses:
Lease operating expenses for the three months ended June 30, 2001, were $49.0
million, or 45% higher than for the three months ended June 30, 2000. The
majority of this increase is due to a $9.7 million increase in steam costs
related to the Company's thermal oil producing operations. Lease operating
expenses per BOE were $10.30 in the second quarter of 2001, compared to $7.07 in
the same period in 2000.
Domestic: Lease operating expenses per BOE were $10.95 in the second quarter of
2001, compared to $7.12 in the same period in 2000. Higher steam costs
contributed to the higher lease operating expenses per BOE quarter over quarter.
International: Lease operating expenses per BOE were $5.06 in the second quarter
of 2001, compared to $6.58 in the same period in 2000. The decrease 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 $5.4 million and $1.5
million for the three months ended June 30, 2001 and 2000, respectively. For the
three months ended June 30, 2001, exploration costs were comprised of $3.0
million in G&G, $0.5 million in dry hole costs, $0.1 million in delay rentals,
$0.9 million in impairment costs associated with the Accra-Keta Prospect, and
$0.9 million of other exploration related activities. For the three months
ended June 30, 2000, exploration costs were comprised of $0.1 million of dry
hole costs, $0.6 million in G&G, $0.2 million in delay rentals and $0.6 million
of other exploration related activities.
Depreciation, Depletion and Amortization:
Depreciation, depletion and amortization for the three months ended June 30,
2001, reflects a 35% 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.
Gain on Sale of Assets, net:
Gain on sale of assets for the three months ended June 30, 2001, was $0.2
million, 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 June 30, 2000, was $0.4 million, 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 $9.2 million and $7.5 million in the
three months ended June 30, 2001 and 2000, respectively. The 23% increase is
due primarily to a $1.6 million severance payment related to the resignation of
the Company's Chairman, President and Chief Executive Officer in May 2001.
20
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Interest Expense:
Interest expense of $10.4 million for the three months ended June 30, 2001,
increased 23% 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 96% decrease in other expense from the second quarter of 2000 to the second
quarter of 2001 is primarily due to the $2.0 million accrual for a lawsuit
settlement and $0.7 million in costs to evaluate potential business
transactions, which were both included in other expense during the second
quarter of 2000.
Net Income (Loss)
Net income of $2.7 million, $0.16 and $0.14 per common share - basic and
diluted, respectivley, was reported for the three months ended June 30, 2001, as
compared to a net loss of $0.7 million, $(0.04) per common share - basic and
diluted, reported for the same period in 2000.
21
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
RESULTS OF OPERATIONS (SIX MONTHS ENDED JUNE 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:
Six Months
Ended June 30, %
--------------- Increase/
2001 2000 (Decrease)
------ ------ ---------
PRODUCTION:
Oil and condensate - Domestic (MBBLS)..................... 7,573 7,353 3%
Oil and condensate - International (MBBLS)................ 790 978 (19%)
------ ------
Oil and condensate - Total (MBBLS)........................ 8,363 8,331 ---
Natural gas - Domestic (MMCF)............................. 6,782 7,811 (13%)
Natural gas liquids - Domestic (MBBLS).................... 94 85 11%
Equivalent barrels of production - Domestic (MBOE)........ 8,798 8,741 1%
Equivalent barrels of production - International (MBOE)... 790 978 (19%)
------ ------
Equivalent barrels of production - Total (MBOE)........... 9,588 9,719 (1%)
AVERAGE SALES PRICE:
Oil and condensate - Domestic............................. $15.39 $13.12 17%
Oil and condensate - International........................ $17.31 $18.41 (6%)
Oil and condensate - Total................................ $15.58 $13.75 13%
Natural gas - Domestic.................................... $12.48 $ 2.91 329%
LEASE OPERATING EXPENSE:
Average unit production cost(1) per BOE - Domestic........ $11.51 $ 6.70 72%
Average unit production cost(1) per BOE - International... $ 6.43 $ 6.71 (4)%
Average unit production cost(1) per BOE - Total........... $11.09 $ 6.70 66%
(1) Costs incurred to operate and maintain wells and related equipment and
facilities, including ad valorem and severance taxes.
Revenues
Oil and Gas Revenues:
Oil and gas revenues for the six months ended June 30, 2001, were $217.4
million, or 56% higher than oil and gas revenues for the same period in 2000.
This increase is primarily due to a 13% increase in realized oil prices and a
329% increase in realized gas prices. These increases were partially offset by
a 19% decrease in international oil production that resulted from two pipeline
replacements in the first quarter of 2001. First half 2001 oil price
realizations reflect hedging losses of $40.9 million, or $4.89 per barrel,
compared to hedging losses of $51.3 million, or $6.16 per barrel in the first
half of 2000.
Domestic: Oil and gas revenues for the six months ended June 30, 2001, were 68%
higher than oil and gas revenues for the same period in 2000. This increase is
primarily due to a 329% improvement in average realized gas prices and a 17%
improvement in average realized oil prices. The realized oil price of $15.39
per barrel for the first half of 2001 includes negative hedging results of $40.9
million, or $5.40 per barrel of oil, compared to hedging losses of $53.4
million, or $7.26 per barrel in the first half of 2000.
22
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
International: Oil revenues for the six months ended June 30, 2001 decreased 24%
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 second quarter of 2001 relating to international production. The
realized oil price for the first half of 2000 includes hedging gains of $2.08
per barrel of oil.
Gain (loss) on Sale of Assets, net:
Loss on sale of assets for the six months ended June 30, 2001, was $0.1 million,
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 six
months ended June 30, 2000, was $0.5 million, primarily representing a gain on
the sale of certain non-core California properties.
Expenses
Lease Operating Expenses:
Lease operating expenses for the six months ended June 30, 2001, were $106.3
million, or 63% higher than for the six months ended June 30, 2000. This
increase is primarily due to a $31.1 million increase in steam costs resulting
from higher natural gas prices. Lease operating expenses per BOE were $11.09 in
the first half of 2001, compared to $6.70 in the same period in 2000.
Domestic: Lease operating expenses per BOE were $11.51 in the first half of
2001, compared to $6.70 in the same period in 2000. Higher steam costs
accounted for $3.56 of the per BOE increase, period over period.
International: Lease operating expenses per BOE were $6.43 in the first half of
2001, compared to $6.71 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 G&G costs, dry hole costs, delay rentals and
expensed project costs, were $8.0 million and $4.7 million for the six months
ended June 30, 2001 and 2000, respectively. For the six months ended June 30,
2001, exploration costs were comprised of $2.0 million of dry hole costs (for
the dry hole in Ghana), $4.1 million in G&G, $0.1 million in delay rentals, $0.9
million in impairment costs associated with the Accra-Keta prospect, and $0.9
million of other exploration related activities. For the six months ended June
30, 2000, exploration costs were comprised of $3.8 million in G&G (primarily for
3-D seismic acquisition and processing in the Accra-Keta prospect offshore
Ghana), $0.1 million in dry hole costs, $0.2 million in delay rentals, and $0.6
million of other exploration related activities.
Depreciation, Depletion and Amortization:
Depreciation, depletion and amortization for the six months ended June 30, 2001,
reflects a 28% 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
23
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 $16.5 million and $16.2 million for the
six months ended June 30, 2001 and 2000, respectively. The first six 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.
Interest Expense:
Interest expense of $21.6 million for the six months ended June 30, 2001,
increased 28% 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 51% decrease in other expense from the first half of 2000 to the first half
of 2001 is primarily due to a $2.0 million accrual for a lawsuit settlement in
2000 and $0.7 million in costs to evaluate potential business transactions
incurred during the second quarter of 2000.
Net Income (Loss)
Net income of $12.3 million, $0.74 and $0.71 per common share - basic and
diluted, respectively, was reported for the six months ended June 30, 2001, as
compared to net loss of $1.2 million, ($0.07) per common share - basic and
diluted, reported for the same period in 2000.
24
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.
25
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 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At the annual meeting of the stockholders of the Company on May 23, 2001
the following matters were voted on with the following results:
(1) Isaac Arnold, Jr. was elected as a director of the Company with a total of
13,172,274 shares voting in favor and 280,382 shares withheld authority.
(2) Thomas D. Barrow was elected as a director of the Company with a total of
13,172,031 shares voting in favor and 280,625 shares withheld authority.
(3) David H. Batchelder was elected as a director of the Company with a total
of 13,172,274 shares voting in favor and 280,382 shares withheld authority.
(4) Charles M. Elson was elected as a director of the Company with a total of
13,171,878 shares voting in favor and 280,778 shares withheld authority.
(5) Robert L. Gerry, III was elected as a director of the Company with a total
of 13,172,031 shares voting in favor and 280,625 shares withheld authority.
(6) Gary R. Petersen was elected as a director of the Company with a total of
13,172,031 shares voting in favor and 280,625 shares withheld authority.
(7) David Ross was elected as a director of the Company with a total of
13,172,274 shares voting in favor and 280,382 shares withheld authority.
(8) Robert W. Shower was elected as a director of the Company with a total of
13,172,274 shares voting in favor and 280,382 shares withheld authority.
(9) The stockholders approved a proposal to ratify the selection of Arthur
Andersen LLP as the Company's independent auditors for the year ending
December 31, 2001, with a total of 13,346,381 shares voting in favor, a
total of 98,684 shares voting against and a total of 7,591 shares
abstaining.
26
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/A, dated April 4, 2001, reporting Item 4.
Change in Registrant's Certifying Accountant was filed on April 4,
2001.
2) A Current Report on Form 8-K, dated April 23, 2001, reporting Item 9.
Regulation FD Disclosure was filed on April 23, 2001.
3) A Current Report on Form 8-K, dated May 10, 2001, reporting Item 9.
Regulation FD Disclosure was filed on May 10, 2001.
4) A Current Report on Form 8-K, dated May 10, 2001, reporting Item 5.
Other Business was filed on May 10, 2001.
5) A Current Report on Form 8-K, dated June 15, 2001, reporting Item 9.
Regulation FD Disclosure was filed on June 15, 2001.
6) A Current Report on Form 8-K, dated June 29, 2001, reporting Item 9.
Regulation FD Disclosure was filed on June 29, 2001.
27
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,
28
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.
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.
29
NUEVO ENERGY COMPANY
PART II. OTHER INFORMATION (CONTINUED)
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
NUEVO ENERGY COMPANY
(Registrant)
Date: August 13, 2001 By:/s/ Phillip A. Gobe
--------------- ----------------------------
Phillip A. Gobe
Interim President and Chief
Executive Officer
Date: August 13, 2001 By:/s/ Robert M. King
--------------- --------------------------
Robert M. King
Senior Vice President and Chief
Financial Officer
30