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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM _____________________ TO _______________________
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 Identification No.)
incorporation or organization)
1021 MAIN, 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 [ ]
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.
Common Stock, par value $.01 per share. Shares outstanding on
November 6, 2002: 19,179,544.
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NUEVO ENERGY COMPANY
TABLE OF CONTENTS
PAGE
----------
PART I
Item 1. Financial Statements
Condensed Consolidated Statements of Income.................................... 3
Condensed Consolidated Balance Sheets.......................................... 4
Condensed Consolidated Statements of Cash Flows................................ 5
Condensed Consolidated Statements of Comprehensive Income (Loss)............... 6
Notes to the Condensed Consolidated Financial Statements....................... 7
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................................... 17
Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation Reform Act of 1995.......... 24
Item 3. Quantitative and Qualitative Disclosures About Market Risk......................... 24
Item 4. Disclosure Controls and Procedures................................................. 25
PART II
Item 1. Legal Proceedings.................................................................. 26
Item 2. Changes in Securities and Use of Proceeds.......................................... 26
Item 3. Defaults Upon Senior Securities.................................................... 26
Item 4. Submission of Matters to a Vote of Security-Holders................................ 26
Item 5. Other Information.................................................................. 26
Item 6. Exhibits and Reports on Form 8-K................................................... 26
Signatures ........................................................................ 27
2
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE DATA)
(UNAUDITED)
Quarter Ended Nine Months Ended
September 30, September 30,
--------------------------- ------------------------
2002 2001 2002 2001
---------- ---------- ---------- ----------
Revenues
Crude oil and liquids.................................. $ 78,676 $ 71,263 $ 224,612 $ 201,874
Natural gas............................................ 9,444 9,759 24,198 90,739
Other.................................................. 3,515 98 3,563 213
---------- ---------- ---------- ----------
91,635 81,120 252,373 292,826
---------- ---------- ---------- ----------
Costs and Expenses
Lease operating expenses............................... 39,524 39,797 112,155 145,370
Exploration costs...................................... 2,318 5,825 3,800 12,992
Depletion, depreciation and amortization............... 19,277 18,250 56,281 57,057
Impairment of oil and gas properties................... -- 134 -- 1,014
General and administrative............................. 6,525 9,502 19,840 26,007
Other.................................................. 186 323 (11) 2,213
Loss (gain) on disposition of properties............... (620) (78) (15,946) 53
---------- ---------- ---------- ----------
67,210 73,753 176,119 244,706
---------- ---------- ---------- ----------
Income From Operations...................................... 24,425 7,367 76,254 48,120
Derivative gain (loss)................................. (3,371) 115 (4,304) 112
Interest income........................................ 53 268 227 1,099
Interest expense....................................... (9,528) (10,635) (27,744) (32,219)
Dividends on TECONS.................................... (1,653) (1,653) (4,959) (4,959)
---------- ---------- ---------- ----------
Income (Loss) from Continuing Operations Before Income Tax..
9,926 (4,538) 39,474 12,153
Income tax expense (benefit)
Current................................................ 1,025 (76) 1,025 5
Deferred............................................... 2,996 (1,679) 14,966 4,965
---------- ---------- ---------- ----------
4,021 (1,755) 15,991 4,970
---------- ---------- ---------- ----------
Net Income (Loss) From Continuing Operations................ 5,905 (2,783) 23,483 7,183
Income from discontinued operations, including loss on
disposition, net of income taxes.................... 250 400 700 2,696
---------- ---------- ---------- ----------
Net Income (Loss)........................................... $ 6,155 $ (2,383) $ 24,183 $ 9,879
========== ========== ========== ==========
Earnings Per Share
Basic
Net income (loss) from continuing operations ....... $ 0.34 $ (0.16) $ 1.37 $ 0.43
Net income from discontinued operations ............ 0.01 0.02 0.04 0.16
---------- ---------- ---------- ----------
Net income (loss)................................... $ 0.35 $ (0.14) $ 1.41 $ 0.59
========== ========== ========== ==========
Diluted
Net income (loss) from continuing operations........ $ 0.34 $ (0.16) $ 1.36 $ 0.41
Net income from discontinued operations ............ 0.01 0.02 0.04 0.16
---------- ---------- ---------- ----------
Net income (loss)................................... $ 0.35 $ (0.14) $ 1.40 $ 0.57
========== ========== ========== ==========
Weighted Average Shares Outstanding
Basic.................................................. 17,399 16,877 17,161 16,686
========== ========== ========== ==========
Diluted................................................ 17,502 16,877 17,308 17,101
========== ========== ========== ==========
See accompanying notes.
3
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)
September 30, December 31,
2002 2001
----------------- ---------------
(UNAUDITED)
ASSETS
Current assets
Cash and cash equivalents.......................................................... $ 4,125 $ 7,110
Accounts receivable, net .......................................................... 44,778 48,304
Inventory.......................................................................... 4,642 3,839
Assets held for sale .............................................................. 819 819
Assets from price risk management activities....................................... 148 19,610
Prepaid expenses and other......................................................... 5,137 2,050
--------- ---------
Total current assets............................................................ 59,649 81,732
--------- ---------
Property and equipment, at cost
Oil and gas properties (successful efforts method)................................. 1,024,020 1,014,429
Land............................................................................... 57,831 55,859
Gas plant facilities............................................................... 8,723 8,723
Other property..................................................................... 14,015 11,347
--------- ---------
1,104,589 1,090,358
Accumulated depletion, depreciation and amortization............................... (365,805) (424,837)
--------- ---------
Total property and equipment, net............................................... 738,784 665,521
--------- ---------
Deferred tax assets, net............................................................... 42,972 70,013
Goodwill............................................................................... 21,745 --
Other assets........................................................................... 25,845 22,546
--------- ---------
Total assets................................................................. $ 888,995 $ 839,812
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable................................................................... $ 30,035 $ 35,771
Accrued interest................................................................... 15,519 5,635
Other accrued liabilities.......................................................... 59,693 57,718
--------- ---------
Total current liabilities....................................................... 105,247 99,124
--------- ---------
Long-term debt
9 3/8% Senior Subordinated Notes due 2010.......................................... 150,000 150,000
9 1/2% Senior Subordinated Notes due 2008.......................................... 257,210 257,210
9 1/2% Senior Subordinated Notes due 2006.......................................... 2,367 2,367
Bank Line of Credit................................................................ 44,000 41,500
Interest rate swaps................................................................ 12,946 (633)
--------- ---------
Total long-term debt............................................................ 466,523 450,444
--------- ---------
Other long-term liabilities............................................................ 18,130 15,337
TECONS................................................................................. 115,000 115,000
Stockholders' equity
Preferred stock, 7% Cumulative Convertible, $1.00 par value; 10,000,000 shares
authorized; none issued and outstanding in 2002 and 2001........................ -- --
Common stock, $0.01 par value, 50,000,000 shares authorized; issued 23,029,541 in
2002 and 20,905,796 in 2001..................................................... 230 209
Additional paid-in capital...................................................... 387,567 366,792
Treasury stock (at cost) 3,871,149 shares in 2002 and 3,902,721 shares in 2001..... (75,726) (75,855)
Stock held by benefit trust, 67,137 shares in 2002 and 122,995 shares in 2001... (1,081) (2,919)
Deferred stock compensation..................................................... 485 (902)
Accumulated other comprehensive income (loss)................................... (12,611) 11,534
Accumulated deficit............................................................. (114,769) (138,952)
--------- ---------
Total stockholders' equity................................................... 184,095 159,907
--------- ---------
Total liabilities and stockholders' equity................................ $ 888,995 $ 839,812
========= =========
See accompanying notes.
4
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
Quarter Ended Nine Months Ended
September 30, September 30,
-------------------------- --------------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------
Cash flows from operating activities
Net income (loss)......................................... $ 6,155 $ (2,383) $ 24,183 $ 9,879
Adjustments to reconcile net income to net cash provided
by operating activities
Depletion, depreciation and amortization............... 19,277 18,250 56,281 57,057
Dry hole costs......................................... -- 4,506 -- 6,492
Impairment of oil and gas properties................... -- 134 -- 1,014
Amortization of debt financing costs................... 633 602 1,899 1,797
Loss (gain) on disposition of properties............... (620) (78) (15,946) 53
Deferred income taxes.................................. 2,996 (1,679) 14,966 4,965
Derivative (gain) loss................................. 3,371 (115) 4,304 (112)
Non-cash effect of discontinued operations............. (144) 795 1,939 3,543
Other.................................................. 1,981 67 2,342 384
---------- ---------- --------- ----------
33,649 20,099 89,968 85,072
Working capital and other changes, net of non-cash
transactions
Accounts receivable.................................... 1,971 9,633 5,778 10,659
Accounts payable....................................... 7,669 (14,740) (20,382) 5,837
Other.................................................. (4,789) 20,286 (7,857) 61
---------- ---------- ---------- ----------
Net cash provided by operating activities........... 38,500 35,278 67,507 101,629
---------- ---------- ---------- ----------
Cash flows from investing activities
Additions to oil and gas properties....................... (9,302) (34,188) (37,647) (104,223)
Acquisition of Athanor Resources, Inc..................... (61,312) -- (61,312) --
Acquisitions of oil and gas properties.................... -- (64) -- (32,769)
Additions to gas plants and other facilities.............. (1,318) (1,173) (3,524) (2,555)
Proceeds from sale of properties.......................... 2,112 -- 26,968 --
---------- ---------- ---------- ----------
Net cash used in investing activities............... (69,820) (35,425) (75,515) (139,547)
---------- ---------- ---------- ----------
Cash flows from financing activities
Debt issuance and modification costs...................... -- -- -- (97)
Payments of long-term debt................................ -- (125) -- (150)
Net borrowings of credit facility......................... 35,200 -- 2,500 --
Proceeds from exercise of stock options................... -- 68 1,229 3,691
Purchase of treasury shares............................... -- -- -- (2,085)
Other proceeds........................................... -- -- 1,294 --
---------- ---------- ---------- ----------
Net cash provided by(used in) financing activities.. 35,200 (57) 5,023 1,359
---------- ---------- ---------- ----------
Increase (decrease) in cash and cash equivalents............ 3,880 (204) (2,985) (36,559)
Cash and cash equivalents
Beginning of period.................................... 245 3,092 7,110 39,447
---------- ---------- ---------- ----------
End of period.......................................... $ 4,125 $ 2,888 $ 4,125 $ 2,888
========== ========== ========== ==========
See accompanying notes.
5
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(IN THOUSANDS)
(UNAUDITED)
Quarter Ended Nine Months Ended
September 30, September 30,
-------------------------- --------------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------
Net income (loss)........................................... $ 6,155 $ (2,383) $ 24,183 $ 9,879
Other comprehensive income, net of tax:
Cumulative-effect transition adjustment .............. -- -- -- (15,976)
Reclassification adjustment for settled contracts..... 3,586 6,072 1,985 28,630
Net change in fair value of derivative instruments.... (11,591) 4,070 (26,130) (9,672)
----------- ----------- ----------- -----------
Other comprehensive income (loss)................ (8,005) 10,142 (24,145) 2,982
----------- ----------- ----------- -----------
Comprehensive income (loss)........................... $ (1,850) $ 7,759 $ 38 $ 12,681
=========== =========== =========== ===========
See accompanying notes.
6
NUEVO ENERGY COMPANY
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION
Our 2001 Annual Report on Form 10-K includes a summary of our
significant accounting policies and other disclosures. You should read it in
conjunction with this Quarterly Report on Form 10-Q. The financial statements as
of September 30, 2002, and for the quarters and nine months ended September 30,
2002 and 2001, are unaudited. The balance sheet as of December 31, 2001, is
derived from the audited balance sheet filed in the Form 10-K. These financial
statements have been prepared pursuant to the rules and regulations of the U.S.
Securities and Exchange Commission and do not include all disclosures required
by accounting principles generally accepted in the United States. We have made
adjustments, all of which are of a normal, recurring nature, to fairly present
our interim period results. Information for interim periods may not indicate the
results of operations for the entire year due to the seasonal nature of our
business. The prior period information also includes reclassifications which
were made to conform to the current period presentation. These reclassifications
have no effect on our reported net income, cash flows or stockholders' equity.
Our accounting policies are consistent with those discussed in our Form
10-K, except as discussed below. You should refer to our Form 10-K for a further
discussion of those policies.
Accounting for the Impairment or Disposal of Long-Lived Assets.
In October 2001, the Financial Accounting Standards Board ("FASB")
issued Statement of Financial Accounting Standards ("SFAS") No. 144, Accounting
for the Impairment or Disposal of Long-Lived Assets. This Statement requires
that long-lived assets that are to be disposed of by sale be measured at the
lower of book value or fair value less cost to sell. The standard also expanded
the scope of discontinued operations to include all components of an entity with
operations that can be distinguished from the rest of the entity and that will
be eliminated from the ongoing operations of the entity in a disposal
transaction. We adopted the provisions of this statement effective January 1,
2002 and have presented certain property dispositions as discontinued operations
in accordance with SFAS No. 144. (See Note 3).
Goodwill and Other Intangible Assets.
In June 2001, the FASB issued SFAS No. 142, Goodwill and Other
Intangible Assets. This Statement requires discontinuing amortization of
goodwill after 2001 and requires that goodwill be tested for impairment. The
impairment test requires allocating goodwill and all other assets and
liabilities to business levels referred to as reporting units. The fair value of
each reporting unit that has goodwill is determined and compared to the book
value of the reporting unit. If the fair value of the reporting unit is less
than the book value (including goodwill), then a second test is performed to
determine the amount of the impairment.
If the second test is necessary, the fair value of the reporting unit's
individual assets and liabilities is deducted from the fair value of the
reporting unit. This difference represents the implied fair value of goodwill,
which is compared to the book value of the reporting unit's goodwill. Any excess
of the book value of goodwill over the implied fair value of goodwill is the
amount of the impairment.
The goodwill impairment test is performed annually, and also at interim
dates upon the occurrence of significant events. Significant events include: a
significant adverse change in legal factors or business climate; an adverse
action or assessment by a regulator; a more-likely-than-not expectation that a
reporting unit or significant portion of a reporting unit will be sold;
significant adverse trends in current and future oil and gas prices;
nationalization of any of the Company's oil and gas properties; or, significant
increases in a reporting unit's carrying value relative to its fair value. We
adopted the provisions of this statement January 1, 2002. We did not have or
record goodwill until the third quarter of 2002. During the third quarter 2002,
we recorded $21.7 million of goodwill in connection with our acquisition of
Athanor Resources, Inc. (See Note 2).
Accounting for Asset Retirement Obligations.
In August 2001, the FASB issued SFAS No. 143, Accounting for Asset
Retirement Obligations. This Statement requires companies to record a liability
relating to the retirement and removal of assets used in their business. The
liability is discounted to its present value, with a corresponding increase to
the related asset value.
7
Over the life of the asset, the liability will be accreted to its future value
and eventually extinguished when the asset is taken out of service. The
provisions of this Statement are effective for fiscal years beginning after June
15, 2002. We are currently evaluating the effects of this pronouncement and will
complete our evaluation during the fourth quarter of 2002. We will adopt this
standard on January 1, 2003.
Accounting for Gains and Losses from Extinguishment of Debt.
In April 2002, the FASB issued SFAS No. 145, Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections. This Statement rescinds SFAS No. 4, Reporting Gains and Losses from
Extinguishment of Debt, which required all gains and losses from the
extinguishment of debt to be aggregated and, if material, classified as an
extraordinary item, net of income taxes. As a result, the criteria in Accounting
Principles Board Opinion ("APB") 30 will now be used to classify those gains and
losses. Any gain or loss on the extinguishment of debt that was classified as an
extraordinary item in prior periods presented that does not meet the criteria in
APB 30 for classification as an extraordinary item shall be reclassified. The
provisions of this statement are effective for fiscal years beginning after
January 1, 2003.
Accounting for Costs Associated with Exit or Disposal Activities.
In July 2002, the FASB issued SFAS No. 146, Accounting for Costs
Associated with Exit or Disposal Activities. This Statement requires the
recognition of costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to an exit or disposal plan.
The provisions of this Statement are effective for exit or disposal activities
initiated after December 31, 2002.
2. MERGER WITH ATHANOR RESOURCES, INC.
Effective September 18, 2002, pursuant to an Agreement and Plan of
Merger, a wholly owned subsidiary of Nuevo Energy Company was merged with and
into Athanor Resources, Inc. ("Athanor"), a Delaware corporation, and Athanor
became the surviving wholly owned subsidiary of Nuevo Energy Company. In
connection with the merger, Nuevo issued approximately 2.0 million shares of
common stock for all of the common and preferred stock of Athanor. The results
of Athanor's operations have been included in our consolidated financial
statements effective September 18, 2002.
The merger was accounted for using the purchase method of accounting.
The purchase price totaling approximately $101.4 million included a combination
of $61.3 million of available cash and additional borrowings, the issuance of
approximately $20.1 million of our common stock (approximately 2.0 million
shares) to Athanor stockholders, and the fair value of the net liabilities
assumed of approximately $20.0 million. The following table summarizes the
estimated fair value of the assets acquired and liabilities assumed at the date
of acquisition. We are in the process of finalizing the fair value of the assets
and liabilities assumed, thus, the allocation is subject to refinement.
(In thousands)
--------------
Current assets................................................. $ 2,008
Property, plant and equipment.................................. 101,737
Goodwill....................................................... 21,745
--------
Total assets acquired..................................... 125,490
--------
Current liabilities............................................ 4,599
Long-term debt................................................. 20,000
Deferred tax liability......................................... 19,494
--------
Total liabilities assumed................................. 44,093
--------
Net assets acquired....................................... $ 81,397
--------
The allocation of the purchase price resulted in approximately $21.7
million allocated to goodwill which is not expected to be deductible for tax
purposes. This goodwill is attributable to a premium paid for Athanor because
the acquisition gives Nuevo a new core area with increasing growth
opportunities, diversifies our asset base with higher margin properties and was
financed with a component of equity. Other accrued merger costs of $1.6 million
include capitalizable third party transaction costs.
8
The merger included certain non-cash investing and financing activities
not reflected in the Statement of Cash Flows as follows:
(In thousands)
----------------
Common stock issued............................................ $ 20,086
Long-term debt assumed......................................... 20,000
Subsequent to the acquisition, the long-term debt assumed of $20.0
million was paid off.
The following unaudited pro forma condensed income statement
information has been prepared to give effect to the merger as if such
transaction had occurred at the beginning of the periods presented. The
historical results of operations have been adjusted to reflect the difference
between Athanor's historical depletion, depreciation and amortization and such
expense calculated based on the value allocated to the assets acquired in the
merger. The information presented is not necessarily indicative of the results
of future operations of the merged companies.
Quarter Ended Nine Months Ended
September 30, September 30,
-------------------------- -----------------------------
2002 2001 2002 2001
----------- ----------- ------------- ------------
Revenues.............................................. $ 97,127 $ 87,637 $ 267,930 $ 321,632
Income (Loss) from Continuing Operations.............. 6,764 (1,927) 25,542 14,895
Net Income (Loss)..................................... 7,014 (1,534) 26,242 17,584
Earnings Per Share
Basic
Income (Loss) from Continuing Operations....... 0.35 (0.10) 1.34 0.80
Net Income (Loss).............................. 0.36 (0.08) 1.37 0.94
Diluted
Income (Loss) from Continuing Operations....... 0.35 (0.10) 1.32 0.78
Net Income (Loss).............................. 0.36 (0.08) 1.36 0.92
NYMEX prices
Crude oil........................................ $ 28.27 $ 26.76 $ 25.39 $ 27.82
Natural gas...................................... 3.22 2.79 3.03 4.95
3. DISCONTINUED OPERATIONS
In 2002, we sold a majority of our oil and gas properties located in
Texas, Alabama and Louisiana (Eastern properties) for approximately $9.0
million. We recognized a $0.2 million gain on the sale of these properties.
Historical results of operations from these properties and the gain on sale are
classified as discontinued operations in our statements of income.
9
4. RESTRUCTURING AND SEVERANCE CHARGES
We terminated our California field operations and human resources
outsourcing agreements effective March 15, 2002. We brought the human resources
function in-house and we now employ the field employees working on our
California properties. Our exploration and production operations were
reorganized to create a smaller, more focused exploitation program and we
eliminated our California exploration program along with approximately 20
technical positions in late 2001. The following table details the amounts
related to our restructuring:
Liability at Liability at
December 31, Payments in September 30,
2001 2002 2002
----------------------- ------------------------ ----------------------
(In thousands)
Severance, benefits and other.... $ 1,675 $ 1,675 $ --
Contract termination ............ 2,681 2,681 --
----------------------- ------------------------ ----------------------
$ 4,356 $ 4,356 $ --
======================= ======================== ======================
5. EARNINGS PER SHARE
SFAS No. 128, Earnings per Share, requires a reconciliation of the
numerator (income) and denominator (shares) of the basic earnings per share
computation to the numerator and denominator of the diluted earnings per share
computation. The reconciliation is as follows:
Quarter Ended September 30,
-------------------------------------------------------------------------
2002 2001
---------------------------------- ----------------------------------
Net Income Shares Net Income Shares
---------------- -------------- --------------- ---------------
(in thousands)
Basic Earnings Per Share
Income (loss) from continuing
operations.................. $5,905 17,399 $(2,783) 16,877
Income (loss) from discontinued
operations.................. 250 400
---------------- ---------------
Earnings Basic........................ 6,155 $(2,383)
Effect of Diluted Securities
Stock options and restricted
stock....................... 38 --
Shares held by benefit trust.... 65 --
---------------- -------------- --------------- ---------------
Earnings - Diluted.................... $6,155 17,502 $(2,383) 16,877
================ ============== =============== ===============
Year to Date Ended September 30,
-------------------------------------------------------------------------
2002 2001
---------------------------------- ----------------------------------
Net Income Shares Net Income Shares
---------------- -------------- --------------- ---------------
(in thousands)
Basic Earnings Per Share
Income (loss) from continuing
operations.................. $23,483 17,161 $7,183 16,686
Income (loss) from discontinued
operations.................. 700 2,696
---------------- ---------------
Earnings Basic........................ 24,183 9,879
Effect of Diluted Securities
Stock options and restricted
stock....................... 86 262
Shares held by benefit trust.... (8) 61 (194) 153
---------------- -------------- --------------- ---------------
Earnings - Diluted.................... $24,175 17,308 $9,685 17,101
================ ============== =============== ===============
10
6. LONG-TERM DEBT
Our long-term debt consisted of the following:
September 30, December 31,
2002 2001
----------------- ------------------
(In thousands)
9 3/8% Senior Subordinated Notes due 2010 .......................... $ 150,000 $ 150,000
9 1/2% Senior Subordinated Notes due 2008 .......................... 257,210 257,210
9 1/2% Senior Subordinated Notes due 2006 .......................... 2,367 2,367
Bank credit facility (4.75% on September 30, 2002 and 3.71% on
December 31, 2001).............................................. 44,000 41,500
----------------- ------------------
Total debt................................................. 453,577 451,077
Interest rate swaps - fair value adjustment (Note 7)................ 990 (633)
Interest rate swap - termination gain.............................. 11,956 --
----------------- ------------------
Long-term debt...................................................... $ 466,523 $ 450,444
================= ==================
7. FINANCIAL INSTRUMENTS
We have entered into commodity swaps, put options and interest rate
swaps. The commodity swaps and put options are designated as cash flow hedges
and the interest rate swaps are designated as fair value hedges in accordance
with SFAS 133. Quantities covered by the commodity swaps and put options are
based on West Texas Intermediate ("WTI") barrels. The average price realized per
barrel from our production is expected to average 73% of the WTI price per
barrel, therefore, each WTI barrel hedges approximately 1.38 barrels of our
production.
Derivative Instruments Designated as Cash Flow Hedges.
At September 30, 2002, we had entered into the following cash flow
hedges:
WTI Crude Oil Natural Gas
------------------------------ ------------------------------------------
Barrels Average
Per Average MMBTU Price Trading
Day Price / Bbl Per Day MMBTU Hub
--------- ----------------- ----------- ------------ -----------
Swaps (Selling at Fixed Price)
Fourth quarter 2002 ................. 20,000 $ 24.87 12,000 $ 3.87 WAHA
First quarter 2003 .................. 17,500 24.32 -- --
Second quarter 2003 ................. 14,500 23.85 -- --
Third quarter 2003 .................. 13,500 23.62 -- --
Fourth quarter 2003.................. 11,500 23.50 -- --
First quarter 2004................... 11,500 23.31 -- --
Second quarter 2004.................. 4,500 22.82 -- --
Third quarter 2004................... 4,500 22.82 -- --
Fourth quarter 2004.................. 4,500 22.82 -- --
First quarter 2005................... 4,500 22.14 -- --
Second quarter 2005.................. 4,500 22.14 -- --
Third quarter 2005................... 4,500 22.14 -- --
Fourth quarter 2005.................. 4,500 22.14 -- --
Put Options (Option Purchased)
Fourth quarter 2002 ................. 9,000 $ 22.00
WTI Crude Collars (Floor Purchased, Ceiling Sold)
First quarter 2003................... 10,000 $ 22.00 - 28.91
Second quarter 2003.................. 10,000 22.00 - 28.91
Third quarter 2003................... 10,000 22.00 - 28.91
Fourth quarter 2003.................. 10,000 22.00 - 28.91
11
Natural Gas
------------------------------------------
Average
MMBTU Price Trading
Per Day MMBTU Hub
Swaps (Selling at Fixed Price)
First quarter 2004................... 8,000 $ 3.905 Socal
Second quarter 2004.................. 8,000 3.905 Socal
Third quarter 2004................... 8,000 3.905 Socal
Fourth quarter 2004.................. 8,000 3.905 Socal
First quarter 2005................... 8,000 3.85 Socal
Second quarter 2005.................. 8,000 3.85 Socal
Third quarter 2005................... 8,000 3.85 Socal
Fourth quarter 2005.................. 8,000 3.85 Socal
Subsequent to September 30, 2002, we entered into the following cash
flow hedges:
Natural Gas Collars (Floor Purchased, Ceiling Sold)
First quarter 2003 ................. 6,000 $3.70 - 4.295 WAHA
Second quarter 2003 ................ 6,000 3.70 - 4.295 WAHA
Third quarter 2003 ................. 6,000 3.70 - 4.295 WAHA
Fourth quarter 2003................. 6,000 3.70 - 4.295 WAHA
We recorded in oil and gas revenues a loss of $6.0 million related to
our settled swaps in the third quarter of 2002. During the quarter ended
September 30, 2002, our put options on 9,000 WTI Bbls/day expired and we
recorded a loss of $1.1 million which is reflected in our statements of income
as a reduction of revenue.
Derivative Instruments Designated as Fair Value Hedges.
We entered into three interest rate swap agreements with notional
amounts totaling $200 million, to hedge a portion of the fair value of our 9
1/2% Notes due 2008 and our 9 3/8% Notes due 2010. During the nine months ended
September 30, 2002, we recognized $4.9 million as a reduction of interest
expense under these hedges. Under the terms of the agreements for the 9 3/8%
Notes, the counterparty paid us a weighted average fixed annual rate of 9 3/8%
on total notional amounts of $150 million, and we paid the counterparty a
variable annual rate equal to the six-month and three-month LIBOR rate plus a
weighted average rate of 3.49%. Under the terms of the agreement for the 9 1/2%
Notes, the counterparty paid us a weighted average fixed annual rate of 9 1/2%
on total notional amounts of $50 million, and we paid the counterparty a
variable annual rate equal to the six-month LIBOR rate plus a weighted average
rate of 3.92%.
On August 30, 2002, we terminated our swap transaction relating to the
9 3/8% Notes. As a result of this termination, we received accrued interest of
$2.2 million and the present value of the swap option of $9.6 million. The gain
of $9.6 million will be amortized as a reduction to interest expense over the
life of the 9 3/8% Notes.
On September 6, 2002, we terminated the swap transaction on the 9 1/2%
Notes and received $0.5 million in accrued interest and the present value of the
swap option of $2.5 million. The gain of $2.5 million will be amortized as a
reduction to interest expense over the life of the 9 1/2% Notes.
On August 30, 2002, we entered into a new interest rate swap agreement
with a notional amount of $50 million, to hedge a portion of the fair value of
our 9 3/8% Notes due 2010. This swap is designated as a fair value hedge and is
reflected as an increase of long-term debt of $1.0 million as of September 30,
2002, with a corresponding increase in other long-term assets. In September
2002, we recorded $0.1 million as a reduction of interest expense. Under the
terms of this agreement, the counterparty pays us a weighted average fixed
annual rate of 9 3/8% on the total notional amount of $50 million and we pay the
counterparty a variable annual rate equal to the six-month LIBOR rate plus a
weighted average rate of 4.71%.
12
Derivative Instruments Not Designated as Hedges.
In December 2001, Enron Corp. ("Enron") and certain of its affiliates
filed voluntary petitions for reorganization under Chapter 11 of the United
States Bankruptcy Code. Once a deterioration in creditworthiness creates
uncertainty as to whether the future cash flows from the hedging instrument will
be highly effective in offsetting the hedged risk, the derivative instrument is
no longer considered highly effective and no longer qualifies for hedge
accounting treatment. At such time, the fair value of the derivative asset or
liability is adjusted to its new fair value, with the change in value being
charged to current earnings. The net gain or loss of the derivative instruments
previously reported in other comprehensive income remains in accumulated other
comprehensive income and is reclassified into earnings during the period in
which the originally designated hedged items affect earnings. During the third
quarter, $1.3 million was reclassified into revenue and at September 30, 2002, a
deferred gain of $0.7 million remains in accumulated other comprehensive income
and $0.4 million remains in deferred taxes related to the outstanding Enron
options, which will be reclassified into earnings when the hedged production
occurs during the remainder of 2002. In June 2002, we sold our Enron bankruptcy
claim relating to these derivatives for $1.3 million, and due to the buyer's
recourse under the terms of the agreement, it is reflected in long-term
liabilities.
In 2001 and 2000, we entered into call spreads that terminate in
December 2003, with the anticipation of using the proceeds to offset a
contingent payment obligation to Unocal. Subsequent to entering into the call
spreads, the market fell and as a result, offsetting call spreads were purchased
to economically nullify the trade. All of our existing call spreads had been
offset through the purchase of a mirror spread, however, the mirror call spread
had been entered into with Enron and was cancelled in December 2001. The
remaining mirror call spread is not designated as a hedging instrument and is
marked-to-market with changes in fair value recognized currently in earnings.
The fair value of the call spread decreased during the quarter ended September
30, 2002, and we recorded a loss of $0.5 million. At September 30, 2002, $2.4
million is reflected in other long-term liabilities.
With the acquisition of Athanor, we assumed two natural gas hedge
positions. A swap of 20,000 MMBTU per month for the fourth quarter 2002 with a
fixed NYMEX price of $2.52/MMBTU and a NYMEX to Permian basis swap at an average
price spread of $0.18/MMBTU.
Included in derivative gain/loss in the third quarter is a $2.9 million
derivative loss related to oil swap transactions that did not qualify for hedge
accounting treatment. The swap transactions going forward will qualify for hedge
accounting and will be accounted for as cash flow hedges.
13
8. SEGMENTS
Our operations are the exploration for and production of crude oil and
natural gas. For segment reporting purposes, domestic producing areas have been
aggregated as one reportable segment due to similarities in their operations as
permitted by SFAS No. 131, Disclosures About Segments of an Enterprise and
Related Information. Financial information by reportable segment is presented
below:
For the Quarter Ended September 30, 2002
---------------------------------------------------------------------
Oil and Gas Oil and Gas
Domestic International Other (1) Total
--------------- --------------- -------------- --------------
Revenues from external customers............. $ 77,266 $ 10,854 $ 3,515 $ 91,635
Operating income (loss) before income tax.... 28,895 2,984 (21,953) 9,926
For the Quarter Ended September 30, 2001
---------------------------------------------------------------------
Oil and Gas Oil and Gas
Domestic International Other (1) Total
--------------- --------------- -------------- --------------
Revenues from external customers............. $ 68,600 $ 12,422 $ 98 $ 81,120
Operating income (loss) before income tax.... 16,985 (24) (21,499) (4,538)
For the Nine Months Ended September 30, 2002
---------------------------------------------------------------------
Oil and Gas Oil and Gas
Domestic International Other (1) Total
--------------- --------------- -------------- --------------
Revenues from external customers............. $ 222,288 $ 26,522 $ 3,563 $ 252,373
Operating income (loss) before income tax.... 88,980 9,128 (58,634) 39,474
For the Nine Months Ended September 30, 2001
---------------------------------------------------------------------
Oil and Gas Oil and Gas
Domestic International Other (1) Total
--------------- --------------- -------------- --------------
Revenues from external customers............. $ 266,465 $ 26,148 $ 213 $ 292,826
Operating income (loss) before income tax.... 71,955 4,169 (63,971) 12,153
---------------------------------------------
(1) Includes unallocated corporate expenses.
9. CONTINGENCIES AND OTHER MATTERS
On September 22, 2000, we were named as a defendant in the lawsuit
Thomas Wachtell et al. versus Nuevo Energy Company in the Superior Court of
Los Angeles County, California. We successfully removed this lawsuit to the
United States District Court for the Central District of California. The
plaintiffs, who own interests in the Point Pedernales properties, asserted
numerous causes of action including breach of contract, fraud and conspiracy
in connection with the plaintiffs' allegation that: (i) royalties had not been
properly paid to them for production from the Point Pedernales field, (ii)
payments had not been made to them related to production from the Pescado and
Sacate fields and (iii) we had failed to recognize the plaintiffs interests in
the Tranquillon Ridge project. We settled this lawsuit in June 2002 for, among
other matters, making a payment to plaintiffs of $3.4 million, and receiving
from plaintiffs certain interests in properties and extinguishing certain
contract rights of plaintiffs. We established a reserve for this contingency
in 2001 and the settlement payment did not have a material impact on our
results of operations or financial position.
On April 5, 2000, we filed a lawsuit against ExxonMobil Corporation in
the United States District Court for the Central District of California, Western
Division. We and ExxonMobil each owned a 50% interest in the Sacate field,
offshore Santa Barbara County, California. We believe that we had been denied a
reasonable opportunity to exercise our rights under the unit operating
agreement. We alleged that ExxonMobil's actions breached the unit operating
agreement and the covenant of good faith and fair dealing. We settled this
lawsuit in June 2002. Under the terms of the settlement agreement, we received
$16.5 million from ExxonMobil and conveyed to them our interest in the Santa
Ynez Unit, our non-consent interest in the adjacent Pescado field and
14
relinquished our right to participate in the Sacate field and recorded a $14.7
million gain related to the sale of this unproved property.
On September 14, 2001, during an annual inspection, we discovered
fractures in the heat affected zone of certain flanges on our pipeline that
connects the Point Pedernales field with onshore processing facilities. We
voluntarily elected to shut-in production in the field while repairs were being
made. The daily net production from this field was approximately 5,000 barrels
of crude oil and 1.2 MMcf of natural gas, representing approximately 11% of our
daily production. We replaced the damaged flanges, as well as others which had
not shown signs of damage. We resumed production in January 2002. During the
third quarter 2002 we reached a final agreement with our underwriters with
respect to our business interruption claim. Accordingly, we recognized $3.0
million of business interruption recoveries during the third quarter 2002. Such
amount is classified in other revenue and we expect to receive payment on this
claim by the end of December 2002. Certain costs related to repair and business
interruption are expected to be covered by insurance based on a tentative
agreement we have with our underwriters. We expect payment with respect to the
repair claims in the next twelve months once the claims are fully adjusted.
On June 15, 2001, we experienced a failure of a carbon dioxide
treatment vessel at the Rincon Onshore Separation Facility ("ROSF") located in
Ventura County, California. There were no injuries associated with this event.
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 natural gas, representing approximately 6% of our
daily production. Crude oil production resumed in early July and full gas sales
resumed by mid August. The cost of repair, less a $50,000 deductible, is
expected to be covered by insurance. We expect to settle the insurance claims
within the next nine months.
We have been named as a defendant in certain other lawsuits incidental
to our business. These actions and claims in the aggregate seek damages against
us and are subject to the inherent uncertainties in any litigation. We are
defending ourselves vigorously in all such matters. We have reserved an amount
that we deem adequate to cover any potential losses related to these matters to
the extent the losses are deemed probable and estimable. This amount is reviewed
periodically and changes may be made, as appropriate. Any additional costs
related to these potential losses are not expected to be material to our
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 our Point Pedernales field with
shore-based processing facilities. The volume of the spill was estimated to be
163 Bbls 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 our insurance,
less a deductible of $0.1 million. As of September 30, 2002, we had received
insurance reimbursements of $4.2 million, with a remaining insurance receivable
of $0.5 million. Costs related to the settlement of claims for natural resource
damage asserted by certain federal and state agencies are also expected to be
covered by insurance.
Our 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 our foreign operations, we 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. We attempt
to conduct our business and financial affairs to protect against political and
economic risks applicable to operations in the various countries where we
operate, but there can be no assurance that we will be successful in so
protecting ourselves. A portion of our investment in the Congo is insured
through political risk insurance provided by Overseas Private Investment Company
("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. We have no deductible for this insurance.
In connection with our February 1995 acquisitions of two subsidiaries
owning interests in the Yombo field offshore Congo, we 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, we 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
15
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:
o a disposition by either us or CMS of its respective Congo
subsidiary,
o either Congo subsidiary's sale of its interest in the Yombo field,
o the acquisition of us or CMS by another consolidated group or
o the failure of CMS's Congo subsidiary or us 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 U.S. income tax purposes. We and CMS have
agreed among ourselves 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. Our potential direct liability could be as much as $38.5
million if a triggering event with respect to us occurs. Additionally, we
believe that CMS's liability (for which we would be jointly liable with an
indemnification right against CMS) could be as much as $56.2 million. During the
second quarter of 2002, we were notified by CMS that they have entered into an
agreement to sell their interest in the Yombo field offshore Congo and that the
transaction will be structured to avoid a triggering event. CMS closed the sale
during the second quarter 2002 but is awaiting approval of the transaction from
the government of Congo.
During 1997, a new government was established in the Congo. Although
the political situation in the Congo has not to date had a material adverse
effect on our operations in the Congo, no assurances can be made that continued
political unrest in West Africa will not have a material adverse effect on us or
our operations in the Congo in the future.
In 1996, the Congo government requested that the convention governing
the Marine I Exploitation Permit be converted to a Production Sharing Agreement
("PSA"). We are under no obligation to convert to a PSA, and our existing
convention is valid and protected by law. Our position is that any conversion to
a PSA would have no detrimental impact to us, otherwise, we will not agree to
any such conversion. Discussions with the government have been ongoing
intermittently since early 1997. To date, no final agreement has been reached
concerning conversion to a PSA.
16
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS MERGER WITH ATHANOR RESOURCES, INC.
Effective September 18, 2002, pursuant to an Agreement and Plan of
Merger, a wholly owned subsidiary of Nuevo Energy Company was merged with and
into Athanor Resources, Inc. ("Athanor"), a Delaware corporation, and Athanor
became the surviving wholly owned subsidiary of Nuevo Energy Company. In
connection with the merger, Nuevo issued approximately 2.0 million shares of
common stock for all of the common and preferred stock of Athanor. The results
of Athanor's operations have been included in the consolidated financial
statements effective September 18, 2002.
The merger was accounted for using the purchase method of accounting.
The purchase price totaling approximately $101.4 million included a combination
of $61.3 million of available cash and additional borrowings, the issuance of
approximately $20.1 million of our common stock (approximately 2.0 million
shares) to Athanor stockholders, and the assumption of net liabilities with a
fair value of approximately $20.0 million.
The allocation of the purchase price resulted in approximately $21.7
million allocated to goodwill which is not expected to be deductible for tax
purposes. This goodwill is attributable to a premium paid for Athanor because
the acquisition gives Nuevo a new core area with increasing growth
opportunities, diversifies our asset base with higher margin properties and was
completed with a component of equity. Other accrued merger costs of $1.6 million
include those capitalizable costs incurred to consummate the transaction,
consisting primarily of professional fees. The allocation of the purchase price
to specific assets and liabilities is based on certain estimates of fair values
and costs which will be adjusted to actual amounts as determined.
RESULTS OF OPERATIONS
Our results of operations are significantly affected by fluctuations in
oil and gas prices. Success in acquiring oil and gas properties and our ability
to maintain or increase production through exploitation activities have also
significantly affected our operating results. We sold our properties located in
Texas, Louisiana and Alabama (Eastern properties) during the second and third
quarters of 2002 and reflected the Eastern properties as discontinued operations
in our financial statements. The following table reflects our production and
average prices for oil and natural gas excluding the Eastern properties for all
periods presented:
Quarter Ended Nine Months Ended
September 30, September 30,
-------------------------- -------------------------
2002 2001 2002 2001
------- ------- ------- -------
Crude Oil and Liquids
Sales Volumes (MBbls/d)
Domestic................ 38.5 38.3 39.6 40.7
International .............. 4.9 6.2 5.1 5.0
------- ------- ------- -------
Total ................... 43.4 44.5 44.7 45.7
======= ======= ======= =======
Sales Prices ($/Bbl)
Unhedged ................... $21.15 $19.88 $18.66 $20.28
Hedged ..................... 19.69 17.39 18.39 16.19
Revenues ($/thousands)
Domestic ................... $73,900 $69,289 $202,090 $227,544
International .............. 12,198 12,754 29,563 28,598
Congo Earnout .............. (1,352) (335) (3,048) (2,453)
Marketing Fees ............. (221) (268) (667) (770)
Hedging .................... (5,849) (10,177) (3,326) (51,045)
------- ------- ------- -------
Total ................. $78,676 $71,263 224,612 201,874
======= ======= ======= =======
17
Quarter Ended Nine Months Ended
September 30, September 30,
------------------------- -------------------------
2002 2001 2002 2001
------ ------ ------- -------
Natural Gas
Sales Volumes (MMcf/d)
Domestic ................... 33.5 29.7 32.3 32.1
====== ====== ======= =======
Sales Prices ($/Mcf)
Unhedged ................... $3.07 $3.56 $2.74 $10.36
Revenues ($/thousands)
Domestic ................... $9,499 $9,909 $24,490 $91,585
Marketing Fees ............. (55) (150) (292) (846)
------ ------ ------- -------
Total ................. $9,444 $9,759 $24,198 $90,739
====== ====== ======= =======
Below is a list of terms commonly used in the oil and gas industry.
/d = per day
Bbl = barrel of crude oil or other liquid hydrocarbons
Bcf = billion cubic feet of natural gas
Bcfe = billion cubic feet of natural gas equivalent
BOE = barrel of oil equivalent, converting gas to oil at the ratio
of 6 Mcf of gas to 1 Bbl of oil
BOPD = barrel of oil per day
MBbl = thousand barrels of crude oil or other liquid hydrocarbons
Mcf = thousand cubic feet of natural gas
MMBbl = million barrels of oil or other liquid hydrocarbons
MMcf = million cubic feet of natural gas
MBOE = thousand barrels of oil equivalent
MMBOE = million barrels of oil equivalent
MMBTU = million British thermal units
18
QUARTER ENDED SEPTEMBER 30, 2002 COMPARED TO QUARTER ENDED SEPTEMBER 30, 2001
We had net income of $6.2 million, or $0.35 per diluted share for the
quarter ended September 30, 2002 as compared to a net loss of $2.4 million, or
$0.14 per diluted share in the same period of 2001.
Revenues
Oil and Gas Revenues. Oil and gas revenues of $88.1 million for the
quarter ended September 30, 2002 increased 9% from $81.0 million in the same
period of 2001 principally due to higher crude oil prices and lower hedging
losses which was partially offset by lower oil production and lower natural gas
prices. The realized oil price in the third quarter of 2002 was $19.69 per Bbl,
an increase of $2.30 per Bbl from the same period in 2001. Crude oil production
averaged 43.4 MBbls/day in the third quarter 2002, a decrease of 2% from the
same period in 2001. The decreased production was due to lower production at
Cymric and Congo due to downtime which was partially offset by higher production
at Midway Sunset and Belridge which have responded to re-steaming. We had a
hedging loss of $5.8 million in the third quarter of 2002 compared to a hedging
loss of $10.2 million in same period of 2001. Natural gas production averaged
33.5 MMcf per day in the third quarter of 2002, an increase of 13% from the 2001
period of 29.7 MMcf per day primarily due to increased production onshore
California. The realized natural gas price in the third quarter 2002 was $3.07
per Mcf, which decreased 14% from $3.56 per Mcf in the prior year period.
Other Revenue. During the third quarter of 2002 we reached a final
agreement with our underwriters with respect to our business interruption claim
(see Contingencies and Other Matters). Accordingly, we recognized $3.0 million
of business interruption recoveries during the third quarter 2002. Such amount
is classified in other revenue and we expect to receive payment on this claim by
the end of December 2002.
Costs and Expenses
Costs and Expenses. Lease operating expenses ("LOE") for the quarter
ended September 30, 2002 was $39.5 million, a slight decrease from the prior
year period. Excluding the steam component, LOE decreased 10% in the third
quarter of 2002 compared to the same period of 2001. Exploration costs were $2.3
million in the quarter ended September 30, 2002 compared to $5.8 million in the
same period of 2001. The 2002 exploration costs included a $2.3 million write
off of our Anaguid permit in Tunisia while the 2001 costs included $4.6 of dry
hole costs. Depreciation, depletion and amortization ("DD&A") was $19.3 million
in the third quarter of 2002 compared to $18.3 million in the prior year period.
The DD&A rate was $4.27 per BOE in the 2002 period compared to $4.01 per BOE in
2001. General and administrative expense of $6.5 million in 2002 was $3.0
million lower than the comparable period in 2001 due to lower outsourcing costs,
lower legal fees and lower project costs.
Derivative Gain (Loss). Our derivative loss of $3.4 million for the
quarter ended September 30, 2002 is comprised of losses on our mark-to-market
derivatives which are not accounted for as hedges.
Interest Expense. Interest expense of $9.5 million in the quarter ended
September 30, 2002 decreased 10% compared to interest expense of $10.6 million
in the same period of 2001. The decrease is primarily due to the benefit of our
interest rate swaps in 2002 of $1.3 million.
Dividends. Dividends on the TECONS were $1.7 million in both quarters
ended September 30, 2002 and 2001. The TECONS pay dividends at a rate of 5.75%
and were issued in December 1996.
Income Tax. We had income tax expense of $4.0 million, including $1.0
million of current tax, in the quarter ended September 30, 2002 compared to a
benefit of $1.8 million in the prior year period. Our effective income tax rate
was 40.5% in 2002 and 40.3% in 2001.
19
YEAR TO DATE SEPTEMBER 30, 2002 COMPARED TO YEAR TO DATE SEPTEMBER 30, 2001
We had net income of $24.2 million, or $1.40 per diluted share for nine
months ended September 30, 2002 as compared to net income of $9.9 million, or
$0.57 per diluted share in the same period of 2001. Our net income for the nine
months ended September 30, 2002 includes an after-tax gain of approximately $8.7
million related to the litigation settlement with ExxonMobil. Excluding this
gain, our net income was $15.4 million, or $0.90 per diluted share.
Revenues
Oil and Gas Revenues. Oil and gas revenues decreased 15% to $248.8
million for the nine months ended September 30, 2002 from $292.6 million in the
same period of 2001 due to significantly lower realized natural gas prices and
lower oil production which was partially offset by lower hedging losses in 2002.
Crude oil production averaged 44.7 MBbls/day for the nine months ended September
30, 2002 compared to 45.7 MBbls/day in the same period of 2001 primarily due to
lower production offshore California due to mechanical downtime. The realized
oil price for the nine months ended September 30, 2002 was $18.39 per Bbl, an
increase of $2.20 per Bbl from the same period in 2001. We had hedging losses of
$3.3 million in the nine months ended September 30, 2002 compared to hedging
losses of $51.0 million in same period of 2001. Natural gas production averaged
32.3 MMcf per day for the nine months ended September 30, 2002 compared to 32.1
MMcf per day for the same period of 2001. The increase was primarily due to
production from the Pakenham field which was acquired in September 2002. The
realized natural gas price for the nine months ended September 30, 2002 was
$2.74 per Mcf, which decreased 74% from $10.36 per Mcf in the comparable period
in 2001.
Other Revenue. During the third quarter of 2002 we reached a final
agreement with our underwriters with respect to our business interruption claim
(see Contingencies and Other Matters). Accordingly, we recognized $3.0 million
of business interruption recoveries during the third quarter 2002. Such amount
is classified in other revenue and we expect to receive payment on this claim by
the end of December 2002.
Costs and Expenses
Costs and Expenses. LOE for the nine months ended September 30, 2002
totaled $112.2 million, as compared to $145.4 million for the 2001 period. The
23% decrease in LOE is principally due to lower steam and workover costs in our
California operations. Exploration costs were $3.8 million in the nine months
ended September 30, 2002, a decrease from $13.0 million in the same period of
2001. Exploration costs in 2002 included a $2.3 million write off of our Anaguid
permit in Tunisia while the 2001 costs included $6.5 million of dry hole costs
and $5.0 million in seismic acquisitions. DD&A decreased to $56.3 million for
the nine months ended September 30, 2002 primarily due to lower oil production.
The DD&A rate was $4.11 per BOE in the 2002 period compared to $4.10 per BOE in
2001. General and administrative expense of $19.8 million in 2002 was $6.2
million lower than the comparable period in 2001 due to a $1.7 million severance
payment in 2001 and lower legal fees, consulting fees and project costs. In
2002, under the terms of a settlement agreement with ExxonMobil, we conveyed to
them our interest in the Santa Ynez Unit, our non-consent interest in the
adjacent Pescado field and relinquished our right to participate in the Sacate
field and recorded a $14.7 million gain related to the sale of this unproved
property.
Derivative Gain (Loss). Our derivative loss for the nine months ended
September 30, 2002 is comprised of losses on our mark-to-market derivatives
which are not accounted for as hedges of $4.1 million and $0.2 million of
ineffectiveness on our hedges.
Interest Expense. Interest expense of $27.7 million for the nine months
ended September 30, 2002 decreased 14% compared to interest expense of $32.2
million in the same period of 2001. The decrease is primarily due to the benefit
of our interest rate swaps in 2002 of $5.0 million.
Dividends. Dividends on the TECONS were $5.0 million in both the nine
months ended September 30, 2002 and 2001. The TECONS pay dividends at a rate of
5.75% and were issued in December 1996.
Income Tax. We had income tax expense of $16.0 million, including $1.0
million of current tax, for the nine months ended September 30, 2002 compared to
an expense of $5.0 million in the prior year period. Our effective income tax
rate was 40.5% in 2002 and 40.3% in 2001.
20
CAPITAL RESOURCES AND LIQUIDITY
We have grown and diversified our operations through acquisitions of
oil and gas properties and the subsequent exploitation and development of these
properties. We have historically funded our operations and acquisitions with
operating cash flows, bank financing, private and public placements of debt and
equity securities, property divestitures and joint ventures with industry
participants.
Net cash provided by operating activities was $67.5 million for the
nine months ended September 30, 2002. In 2002, we invested $61.3 million for
Athanor Resources, Inc., $37.6 million in oil and gas properties and $3.5
million on gas plant and other facilities. We also received $27.0 million in
proceeds from the sale of properties in the nine months ended September 30,
2002.
We believe our working capital, cash flow from operations and available
financing sources are sufficient to meet our obligations as they become due and
to finance our capital budget through 2002. We have a $135 million borrowing
base under our Credit Agreement. Under the most restrictive covenant, $135
million was available at September 30, 2002 of which we had drawn $44.0 million
under the agreement. In August 2002, we issued a $0.8 million letter of credit
under our Credit Agreement. We have an interest rate swap totaling $50 million
on our 9 3/8 % Notes.
CONTINGENCIES AND OTHER MATTERS
On September 14, 2001, during an annual inspection, we discovered
fractures in the heat affected zone of certain flanges on our pipeline that
connects the Point Pedernales field with onshore processing facilities. We
voluntarily elected to shut-in production in the field while repairs were being
made. The daily net production from this field was approximately 5,000 barrels
of crude oil and 1.2 MMcf of natural gas, representing approximately 11% of our
daily production. We replaced the damaged flanges, as well as others which had
not shown signs of damage. We resumed production in January 2002. During the
third quarter of 2002 we reached a final agreement with our underwriters with
respect to our business interruption claim. Accordingly, we recognized $3.0
million of business interruption recoveries during the third quarter of 2002.
Such amount is classified in other revenue and we expect to receive payment on
this claim by the end of December 2002. Certain costs related to repair and
business interruption are expected to be covered by insurance based on a final
agreement reached with our underwriters. We expect payment with respect to the
repair claim in the next nine months once the claim is fully adjusted.
On June 15, 2001, we experienced a failure of a carbon dioxide
treatment vessel at the Rincon Onshore Separation Facility ("ROSF") located in
Ventura County, California. There were no injuries associated with this event.
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 natural gas, representing approximately 6% of our
daily production. Crude oil production resumed in early July and full gas sales
resumed by mid August. The cost of repair, less a $50,000 deductible, is
expected to be covered by insurance. We expect to settle the insurance claims
within the next nine months.
On September 22, 2000, we were named as a defendant in the lawsuit
Thomas Wachtell et al. versus Nuevo Energy Company in the Superior Court of
Los Angeles County, California. We 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,
asserted numerous causes of action including breach of contract, fraud and
conspiracy in connection with the plaintiffs' allegation that: (i) royalties
had not been properly paid to them for production from the Point Pedernales
field, (ii) payments had not been made to them related to production from the
Pescado and Sacate fields and (iii) we have failed to recognize the
plaintiffs' interests in the Tranquillon Ridge project. We settled this
lawsuit in June 2002 for, among other matters, making a payment to plaintiffs
of $3.4 million, and receiving from plaintiffs' certain interests in
properties and extinguishing certain contract rights of plaintiffs. We
established a reserve for this contingency in 2001 and the settlement payment
did not have a material impact on our results of operations or financial
position.
On April 5, 2000, we 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 owned a 50% interest in the Sacate
field, offshore Santa Barbara County, California. We believe that we have been
denied a reasonable opportunity to exercise our rights under the unit operating
agreement. We alleged that ExxonMobil's
21
actions breached the unit operating agreement and the covenant of good faith and
fair dealing. We settled this lawsuit in June 2002. Under the terms of the
agreement, we received $16.5 million from ExxonMobil and conveyed to them our
interest in the Santa Ynez Unit, our non-consent interest in the adjacent
Pescado field and relinquished our right to participate in the Sacate field and
recorded a $14.7 million pre-tax gain related to the sale of this unproved
property.
We have been named as a defendant in certain other lawsuits incidental
to our business. Management does not believe that the outcome of such
litigation will have a material adverse impact on our operating results,
financial condition or liquidity above the amounts we have reserved to cover
any potential losses. However, these actions and claims in the aggregate seek
damages against us and are subject to the inherent uncertainties in any
litigation. We are defending ourselves 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 our Point Pedernales field with
shore-based processing facilities. The volume of the spill was estimated to be
163 Bbls 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 our insurance,
less a deductible of $0.1 million. As of September 30, 2002, we had received
insurance reimbursements of $4.2 million, with a remaining insurance receivable
of $0.5 million. Costs related to the settlement of claims for natural resource
damage asserted by certain federal and state agencies are also expected to be
covered by insurance. We expect to settle the insurance claims within the next
twelve months.
Our 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 our foreign operations, we 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. We attempt
to conduct our business and financial affairs so as to protect against political
and economic risks applicable to operations in the various countries where we
operate, but there can be no assurance that we will be successful in so
protecting ourselves. A portion of our 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. We have no deductible for this
insurance.
In connection with our February 1995 acquisitions of two subsidiaries
owning interests in the Yombo field offshore Congo, we and a wholly-owned
subsidiary of CMS NOMECO Oil & Gas Co. 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, we 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:
o a disposition by either us or CMS of its respective Congo
subsidiary,
o either Congo subsidiary's sale of its interest in the Yombo field,
o the acquisition of us or CMS by another consolidated group or
o the failure of CMS's Congo subsidiary or us 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 U.S. income tax purposes. We and CMS have
agreed among ourselves 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. Our potential direct liability could be as much as $38.5
million if a triggering event with respect to us occurs. Additionally, we
believe that CMS's liability (for which we would be jointly liable with an
indemnification right against CMS) could be as much as $56.2 million. During the
second quarter 2002, we were notified by CMS that they have entered into an
agreement to sell their interest in the Yombo field offshore Congo and the
transaction
22
will be structured to avoid a triggering event. CMS closed the sale during the
second quarter 2002 but is awaiting approval of the transaction from the
government of Congo.
During 1997, a new government was established in the Congo. Although
the political situation in the Congo has not to date had a material adverse
effect on our operations in the Congo, no assurances can be made that continued
political unrest in West Africa will not have a material adverse effect on us or
our operations in the Congo in the future.
In 1996, the Congo government requested that the convention governing
the Marine 1 Exploitation Permit be converted to a Production Sharing Agreement
("PSA"). We are under no obligation to convert to a PSA, and our existing
convention is valid and protected by law. Our position is that any conversion to
a PSA would have no detrimental impact to us, otherwise, we will not agree to
any such conversion. Discussions with the government have been ongoing
intermittently since early 1997. To date, no final agreement has been reached
concerning conversion to a PSA.
ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
Accounting for Asset Retirement Obligations.
In August 2001, the FASB issued SFAS No. 143, Accounting for Asset
Retirement Obligations. This Statement requires companies to record a liability
relating to the retirement and removal of assets used in their business. The
liability is discounted to its present value, with a corresponding increase to
the related asset value. Over the life of the asset, the liability will be
accreted to its future value and eventually extinguished when the asset is taken
out of service. The provisions of this Statement are effective for fiscal years
beginning after June 15, 2002. We are currently evaluating the effects of this
pronouncement.
Accounting for Gains and Losses from Extinguishment of Debt.
In April 2002, the FASB issued SFAS No. 145, Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections. This Statement rescinds SFAS No. 4, Reporting Gains and Losses from
Extinguishment of Debt, which required all gains and losses from extinguishment
of debt to be aggregated and, if material, classified as an extraordinary item,
net of income taxes. As a result, the criteria in Accounting Principles Board
Opinion (APB) 30 will now be used to classify those gains and losses. Any gain
or loss on the extinguishment of debt that was classified as an extraordinary
item in prior periods presented that does not meet the criteria in APB 30 for
classification as an extraordinary item shall be reclassified. The provisions of
this Statement are effective for fiscal years beginning after January 1, 2003.
Accounting for Costs Associated with Exit or Disposal Activities.
In July 2002, the FASB issued SFAS No. 146, Accounting for Costs
Associated with Exit or Disposal Activities. This Statement requires the
recognition of costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to an exit or disposal plan.
The provisions of this Statement are effective for exit or disposal activities
initiated after December 31, 2002.
23
CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report contains or incorporates by reference forward looking
statements within the meaning of Section 27A of the Securities Act of 1933, as
amended, Section 21E of the Securities Exchange Act of 1934 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 in Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operations regarding our financial position, estimated
quantities and net present values of reserves, business strategy, plans and
objectives of our management for future operations and covenant compliance, are
forward looking statements. We can give no assurances that the assumptions upon
which such forward-looking statements are based will prove to be correct.
Important factors that could cause actual results to differ materially from our
expectations are included throughout this document. The cautionary statements
expressly qualify all subsequent written and oral forward-looking statements
attributable to us or persons acting on our behalf.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information contained in this item updates, and should be read in
conjunction with Part II, Item 7A of our Annual Report on Form 10-K for the year
ended December 31, 2001.
At September 30, 2002, we had entered into the following cash flow
hedges:
WTI Crude Oil Natural Gas
------------------------------ ------------------------------------------
Barrels Average
Per Average MMBTU Price Trading
Day Price / Bbl Per Day MMBTU Hub
--------- ----------------- ----------- ------------ -----------
Swaps (Selling at Fixed Price)
Fourth quarter 2002 ................. 20,000 $ 24.87 12,000 $ 3.87 WAHA
First quarter 2003 .................. 17,500 24.32 -- --
Second quarter 2003 ................. 14,500 23.85 -- --
Third quarter 2003 .................. 13,500 23.62 -- --
Fourth quarter 2003.................. 11,500 23.50 -- --
First quarter 2004................... 11,500 23.31 -- --
Second quarter 2004.................. 4,500 22.82 -- --
Third quarter 2004................... 4,500 22.82 -- --
Fourth quarter 2004.................. 4,500 22.82 -- --
First quarter 2005................... 4,500 22.14 -- --
Second quarter 2005.................. 4,500 22.14 -- --
Third quarter 2005................... 4,500 22.14 -- --
Fourth quarter 2005.................. 4,500 22.14 -- --
Put Options (Option Purchased)
Fourth quarter 2002 ................. 9,000 $ 22.00
WTI Crude Collars (Floor Purchased, Ceiling Sold)
First quarter 2003................... 10,000 $ 22.00 - 28.91
Second quarter 2003.................. 10,000 22.00 - 28.91
Third quarter 2003................... 10,000 22.00 - 28.91
Fourth quarter 2003.................. 10,000 22.00 - 28.91
Swaps (Selling at Fixed Price)
First quarter 2004................... 8,000 $ 3.905 Socal
Second quarter 2004.................. 8,000 3.905 Socal
Third quarter 2004................... 8,000 3.905 Socal
Fourth quarter 2004.................. 8,000 3.905 Socal
First quarter 2005................... 8,000 3.85 Socal
Second quarter 2005.................. 8,000 3.85 Socal
Third quarter 2005................... 8,000 3.85 Socal
Fourth quarter 2005.................. 8,000 3.85 Socal
24
Subsequent to September 30, 2002, we entered into the following cash
flow hedges:
Natural Gas
-----------------------------------------
Average
MMBTU Price Trading
Per Day MMBTU Hub
----------- ------------ ----------
Natural Gas Collars (Floor Purchased, Ceiling Sold)
First quarter 2003 .................. 6,000 $3.70 - 4.295 WAHA
Second quarter 2003 ................. 6,000 3.70 - 4.295 WAHA
Third quarter 2003 .................. 6,000 3.70 - 4.295 WAHA
Fourth quarter 2003.................. 6,000 3.70 - 4.295 WAHA
ITEM 4. DISCLOSURE CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
The term "disclosure controls and procedures" is defined in Rule
13a-14(c) of the Securities Exchange Act of 1934, or the Exchange Act. This term
refers to the controls and procedures of a company that are designed to ensure
that information required to be disclosed by a company in the reports that it
files under the Exchange Act is recorded, processed, summarized and reported
within required time periods. Our Chief Executive Officer and our Chief
Financial Officer have evaluated the effectiveness of our disclosure controls
and procedures as of a date within 90 days before the filing of the quarterly
report, and they have concluded that as of that date, our disclosure controls
and procedures were effective at ensuring that required information will be
disclosed on a timely basis in our reports filed under the Exchange Act.
CHANGE IN INTERNAL CONTROLS
We maintain a system of internal controls that are designed to provide
reasonable assurance that our books and records accurately reflect our
transactions and that our established policies and procedures are followed.
There were no significant changes to our internal controls or in other factors
that could significantly affect our internal controls subsequent to the date of
their evaluation by our Chief Executive Officer and our Chief Financial Officer,
including any corrective actions with regard to significant deficiencies and
material weaknesses.
25
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Part I, Item 1, Financial Statements, Note 9, which is incorporated
herein by reference.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS
None.
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(A) EXHIBITS
o 2.1 Agreement and Plan of Merger dated September 18, 2002 by and
among Athanor Resources, Inc., Athanor B.V., Nuevo Energy
Company, Nuevo Texas Inc., Yorktown Energy Partners III, L.P.,
Yorktown Energy IV, L.P., Yorktown Partners LLC, SAFIC S.A.,
Charles de Mestral, J. Ross Craft, Montana Oil and Gas, Ltd.,
David A. Badley, James S. Scott, Glenn Reed, Doug Allison and
Mohamed Yaich (Exhibit 2.1 to our Form 8-K dated September 19,
2002).
o 10.1 Registration Rights Agreement dated September 18, 2002 by and
among Nuevo Energy Company, Yorktown Energy Partners III,
L.P., Yorktown Energy IV, L.P., Yorktown Partners LLC, SAFIC
S.A., Charles de Mestral, J. Ross Craft, Montana Oil and Gas,
Ltd., David A. Badley, James S. Scott, Glenn Reed, Doug
Allison and Mohamed Yaich (Exhibit 10.1 to our Form 8-K dated
September 19, 2002).
o 10.2 Amendment to the 2001 Stock Incentive Plan (Exhibit 99.1 to
our Form S-8 dated November 1, 2002).
(B) REPORTS ON FORM 8-K:
o We filed a current report on Form 8-K/A on September 24, 2002
amending the September 19, 2002 Form 8-K.
o We filed a current report on Form 8-K on September 19, 2002
announcing the acquisition of Athanor Resources, Inc.
o We filed a current report on Form 8-K on August 16, 2002
announcing the resignation of our Board member, David H.
Batchelder.
26
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) the Securities Exchange Act
of 1934, the Registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
NUEVO ENERGY COMPANY
(Registrant)
Date: November 8, 2002 By: /s/ James L. Payne
--------------------------- -----------------------------------
James L. Payne
Chairman, President and
Chief Executive Officer
Date: November 8, 2002 By: /s/ Janet F. Clark
--------------------------- -----------------------------------
Janet F. Clark
Senior Vice President and
Chief Financial Officer
27
CERTIFICATION
I, James L. Payne, being the Chief Executive Officer, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Nuevo Energy
Company;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
(a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this quarterly report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this quarterly report (the "Evaluation
Date"); and
(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: November 8, 2002 By: /s/ James L. Payne
--------------------------- -----------------------------------
James L. Payne
Chairman, President and
Chief Executive Officer
28
I, Janet F. Clark, being the Chief Financial Officer, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Nuevo Energy
Company;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
(a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this quarterly report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this quarterly report (the "Evaluation
Date"); and
(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: November 8, 2002 By: /s/ Janet F. Clark
--------------------------- -----------------------------------
Janet F. Clark
Senior Vice President and
Chief Financial Officer
29
EXHIBIT INDEX
Exhibit Number Description
-------------- --------------------------------------------------------------------------------------
2.1 Agreement and Plan of Merger dated September 18, 2002 by and among Athanor
Resources, Inc., Athanor B.V., Nuevo Energy Company, Nuevo Texas Inc., Yorktown
Energy Partners III, L.P., Yorktown Energy IV, L.P., Yorktown Partners LLC, SAFIC
S.A., Charles de Mestral, J. Ross Craft, Montana Oil and Gas, Ltd., David A. Badley,
James S. Scott, Glenn Reed, Doug Allison and Mohamed Yaich (Exhibit 2.1 to our Form
8-K dated September 19, 2002).
10.1 Registration Rights Agreement dated September 18, 2002 by and among Nuevo Energy
Company, Yorktown Energy Partners III, L.P., Yorktown Energy IV, L.P., Yorktown
Partners LLC, SAFIC S.A., Charles de Mestral, J. Ross Craft, Montana Oil and Gas,
Ltd., David A. Badley, James S. Scott, Glenn Reed, Doug Allison and Mohamed Yaich
(Exhibit 10.1 to our Form 8-K dated September 19, 2002).
10.2 Amendment to the 2001 Stock Incentive Plan (Exhibit 99.1 to our Form S-8 dated
November 1, 2002).