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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 MARCH 31, 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 May 10, 2002:
17,083,426.
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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.................................................... 12
Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation Reform Act of 1995........... 17
Item 3. Quantitative and Qualitative Disclosures About Market Risk.......................... 17
PART II
Item 1. Legal Proceedings................................................................... 18
Item 2. Changes in Securities and Use of Proceeds........................................... 18
Item 3. Defaults Upon Senior Securities..................................................... 18
Item 4. Submission of Matters to a Vote of Security-Holders................................. 18
Item 5. Other Information................................................................... 18
Item 6. Exhibits and Reports on Form 8-K.................................................... 18
Signatures ......................................................................... 19
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
March 31,
------------------------------
2002 2001
------------ ------------
Revenues
Crude oil and liquids ........................................... $ 70,925 $ 66,430
Natural gas ..................................................... 7,201 50,723
Other income .................................................... 6 88
------------ ------------
78,132 117,241
------------ ------------
Costs and expenses
Lease operating expenses ........................................ 38,064 57,287
Exploration costs ............................................... 1,058 2,665
General and administrative expenses ............................. 6,083 7,276
Depreciation, depletion and amortization ........................ 19,158 19,627
Other ........................................................... 24 1,793
Loss on disposition of properties ............................... -- 329
------------ ------------
64,387 88,977
------------ ------------
Income from operations ............................................... 13,745 28,264
Derivative gain (loss) .......................................... (756) (7)
Interest income ................................................. 108 617
Interest expense ................................................ (9,004) (11,135)
Dividends on Company-Obligated Mandatorily Redeemable
Convertible Preferred Securities of Nuevo Financing I
(TECONS) ...................................................... (1,653) (1,653)
------------ ------------
Income before income tax ............................................. 2,440 16,086
Income tax expense
Current ......................................................... -- 560
Deferred ........................................................ 978 5,923
------------ ------------
978 6,483
------------ ------------
Net income ........................................................... $ 1,462 $ 9,603
============ ============
Earnings per common share
Basic ........................................................... $ 0.09 $ 0.58
============ ============
Diluted ......................................................... $ 0.08 $ 0.57
============ ============
Weighted average shares outstanding
Basic ........................................................... 17,000 16,533
============ ============
Diluted ......................................................... 17,176 17,003
============ ============
See accompanying notes.
3
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)
March 31, December 31,
2002 2001
------------ ------------
(UNAUDITED)
ASSETS
Current assets
Cash and cash equivalents ......................................................... $ 2,299 $ 7,110
Accounts receivable, net .......................................................... 44,539 48,304
Inventory ......................................................................... 4,051 3,839
Assets held for sale .............................................................. 819 819
Assets from price risk management activities ...................................... 2,039 19,610
Prepaid expenses and other ........................................................ 3,759 2,050
------------ ------------
Total current assets .......................................................... 57,506 81,732
------------ ------------
Property and equipment, at cost
Land .............................................................................. 56,751 55,859
Oil and gas properties (successful efforts method) ................................ 1,029,693 1,014,429
Gas plant facilities .............................................................. 8,723 8,723
Other facilities .................................................................. 10,487 10,365
------------ ------------
1,105,654 1,089,376
Accumulated depreciation, depletion and amortization .............................. (443,931) (424,837)
------------ ------------
Total property and equipment, net ............................................. 661,723 664,539
------------ ------------
Deferred tax assets, net ............................................................... 69,345 70,013
Other assets ........................................................................... 22,679 23,528
------------ ------------
Total assets ............................................................. $ 811,253 $ 839,812
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable .................................................................. $ 27,958 $ 35,771
Accrued interest .................................................................. 13,409 5,635
Other accrued liabilities ......................................................... 38,338 57,718
------------ ------------
Total current liabilities ..................................................... 79,705 99,124
------------ ------------
Long-term debt (Note 4) ................................................................ 441,789 450,444
Other long-term liabilities ............................................................ 25,713 15,337
TECONS ................................................................................. 115,000 115,000
Commitments and contingencies (Note 7)
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, authorized 50,000,000 shares; issued
20,998,662 shares in 2002 and 20,905,796 shares in 2001 ......................... 210 209
Additional paid-in capital ........................................................ 366,903 366,792
Treasury stock (at cost) 3,877,077 shares in 2002 and 3,902,721 shares in 2001 ... (75,809) (75,855)
Stock held by benefit trust, 61,209 shares in 2002 and 122,995 shares in 2001 ..... (998) (2,919)
Deferred stock compensation ....................................................... (798) (902)
Accumulated other comprehensive income (loss) ..................................... (2,972) 11,534
Accumulated deficit ............................................................... (137,490) (138,952)
------------ ------------
Total stockholders' equity .................................................... 149,046 159,907
------------ ------------
Total liabilities and stockholders' equity ............................... $ 811,253 $ 839,812
============ ============
See accompanying notes.
4
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
Quarter Ended March 31,
2002 2001
------------ ------------
Cash flows from operating activities
Net income ........................................................ $ 1,462 $ 9,603
Adjustments to reconcile net income to net cash provided by
operating activities
Depreciation, depletion and amortization ..................... 19,158 19,627
Dry hole costs ............................................... 90 1,482
Amortization of debt financing costs ......................... 602 596
Loss on sale of assets, net .................................. -- 329
Deferred income taxes ........................................ 978 5,923
Other ........................................................ 797 1,030
------------ ------------
23,087 38,590
Working capital changes, net of non-cash transactions
Accounts receivable .......................................... 3,765 (14,380)
Accounts payable ............................................. (7,813) 19,207
Other ........................................................ (6,717) (12,007)
------------ ------------
Net cash provided by operating activities ............... 12,322 31,410
------------ ------------
Cash flows from investing activities
Additions to oil and gas properties ............................... (15,354) (23,006)
Acquisitions of oil and gas properties ............................ -- (28,168)
Additions to gas plant and other facilities ....................... (1,013) (654)
------------ ------------
Net cash used in investing activities ................... (16,367) (51,828)
------------ ------------
Cash flows from financing activities
Debt issuance and modification costs .............................. -- (97)
Payments of long-term debt ........................................ -- (25)
Net repayments of credit facility ................................. (1,525) --
Proceeds from exercise of stock options ........................... 759 --
Purchase of treasury shares ....................................... -- (2,085)
------------ ------------
Net cash used in financing activities ................... (766) (2,207)
------------ ------------
Decrease in cash and cash equivalents ................................ (4,811) (22,625)
Cash and cash equivalents
Beginning of period .............................................. 7,110 39,447
------------ ------------
End of period .................................................... $ 2,299 $ 16,822
============ ============
See accompanying notes.
5
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(IN THOUSANDS)
(UNAUDITED)
Quarter Ended March 31,
2002 2001
------------ ------------
Net income .......................................................................... $ 1,462 $ 9,603
Unrealized gains (losses) from cash flow hedging activity:
Cumulative-effect transition adjustment (net of tax of $10,784 in
2001) ..................................................................... -- (15,976)
Reclassification of initial cumulative effect transition adjustment at
original value (net of tax of $1,122 in 2002 and $6,084 in 2001) ............ (1,662) 9,013
Additional reclassification adjustments for changes in initial value
to settlement date ( net of tax of $766 in 2002 and $1,328 in 2001) ......... (1,134) 1,967
Changes in fair value of derivative instruments during the period
(net of tax of $7,905 in 2002 and $6,883 in 2001) ........................... (11,710) (10,196)
------------ ------------
Other comprehensive income (loss) ......................................... (14,506) (15,192)
------------ ------------
Comprehensive income (loss) ...................................................... $ (13,044) $ (5,589)
============ ============
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 March 31, 2002, and for the quarters ended March 31, 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. In our opinion, we have made
all adjustments, all of which are of a normal, recurring nature, to fairly
present our interim period results. Information for interim periods may not
necessarily 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 it had no impact on our financial statements.
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, and the related asset value is
increased by the amount of the resulting liability. 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
7
2. RESTRUCTURING CHARGES
Termination of Outsourcing Agreements.
Effective March 15, 2002, we terminated two outsourcing agreements with
the objective of exercising greater control over certain operating functions and
lowering our costs. The terminated outsourcing agreements related to the
California field operations and human resources. We now employ a majority of the
field employees currently working on our California properties and the human
resources function was brought in-house.
Reorganization of Exploration and Production Operations.
We have reorganized our exploration and production operations in an
effort to create a smaller, more focused exploitation program and eliminated our
California exploration program. In connection with the reorganization,
approximately 20 technical positions were eliminated in late 2001.
The following table details the amounts related to our restructuring:
Liability at Liability at
December 31, Payments in March 31,
2001 2002 2002
------------ ------------ ------------
(In thousands)
Severance and benefits ....... $ 1,675 $ 1,452 $ 223
Contract termination ......... 2,681 2,512 169
------------ ------------ ------------
$ 4,356 $ 3,964 $ 392
============ ============ ============
We expect that the balance of the restructuring liability will be paid
during the second quarter of 2002.
3. 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 March 31,
------------------------------------------------------------
2002 2001
---------------------------- ---------------------------
Net Income Shares Net Income Shares
----------- ----------- ----------- -----------
(In thousands)
Earnings - Basic ........................... $ 1,462 17,000 $ 9,603 16,533
Effect of dilutive securities
Stock options and restricted stock ..... -- 122 -- 292
Shares held by benefit trust ........... (38) 54 48 178
----------- ----------- ----------- -----------
Earnings - Diluted ......................... $ 1,424 17,176 $ 9,651 17,003
=========== =========== =========== ===========
4. LONG-TERM DEBT
Our long-term debt consisted of the following:
March 31, 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 (3.58% on March 31, 2002 and 3.71% on
December 31, 2001) ........................................... 39,975 41,500
------------ ------------
Total debt ................................................... 449,552 451,077
Interest rate swaps fair value adjustment ........................ (7,763) (633)
------------ ------------
Long-term debt ................................................... $ 441,789 $ 450,444
============ ============
8
5. 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. Our production is expected to
average 72% of WTI, therefore, each WTI barrel hedges 1.37 barrels of our
production.
Derivative Instruments Designated as Cash Flow Hedges
At March 31, 2002, we had entered into the following cash flow hedges:
WTI
Barrels Per Average
Day Price / Bbl
----------- -----------
Swaps
Second quarter 2002 ........ 13,000 24.45
Third quarter 2002 ......... 13,000 23.95
Fourth quarter 2002 ........ 13,000 24.12
First quarter 2003 ......... 8,000 23.59
Second quarter 2003 ........ 6,000 23.30
Third quarter 2003 ......... 6,000 23.21
Put Options
Second quarter 2002 ........ 14,000 22.00
Third quarter 2002 ......... 9,000 22.00
Fourth quarter 2002 ........ 9,000 22.00
Subsequent to March 31, 2002, we entered into the following cash flow
hedges:
WTI
Barrels Per Average
Day Price / Bbl
----------- -----------
Second quarter 2002 ............. 4,000 $ 26.56
Third quarter 2002 .............. 5,000 26.55
Fourth quarter 2002 ............. 4,000 26.07
First quarter 2003 .............. 2,000 24.50
Second quarter 2003 ............. 4,000 24.13
Third quarter 2003 .............. 4,000 23.91
Fourth quarter 2003 ............. 8,000 23.34
Derivative Instruments Designated as Fair Value Hedges
We have entered into three interest rate swap agreements with notional
amounts totaling $200 million, to hedge the fair value of our 9 1/2% Notes due
2008 and our 9 3/8 % Notes due 2010. These swaps are designated as fair value
hedges and are reflected as a reduction of long-term debt of $7.8 million as of
March 31, 2002, with a corresponding increase in other long-term liabilities.
Under the terms of the agreements for the 9 3/8 % Notes, the counterparty pays
us a weighted average fixed annual rate of 9 3/8 % on total notional amounts of
$150 million, and we pay 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 pays us
a weighted average fixed annual rate of 9 1/2% on total notional amounts 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 3.92%.
9
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 hedge items affect earnings. At March 31, 2002,
a deferred gain of $2.2 million remains in accumulated other comprehensive
income related to the outstanding Enron options, which will be reclassified into
earnings when the hedged production occurs, during the remainder of 2002.
In 2001 and 2000, we entered into call spreads with the anticipation of
using the proceeds to offset the Unocal Contingent payment. 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 call spread with Enron was cancelled. The remaining mirror call spread is
not designated as a hedge instrument and is marked-to-market with changes in
fair value recognized in earnings. The value decreased during the quarter ended
March 31, 2002 and we recorded a loss of $0.6 million. At March 31, 2002, $1.7
million is reflected in other long-term liabilities.
6. 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
allowed 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 March 31, 2002
-----------------------------------------------------------------
Oil and Gas Oil and Gas
Domestic Foreign Other(1) Total
------------ ------------ ------------ ------------
(In thousands)
Revenues from external customers ....... $ 70,728 $ 7,398 $ 6 $ 78,132
Operating income before income tax ..... 18,126 2,344 (18,030) 2,440
For the Quarter Ended March 31, 2001
-----------------------------------------------------------------
Oil and Gas Oil and Gas
Domestic Foreign Other(1) Total
------------ ------------ ------------ ------------
(In thousands)
Revenues from external customers ....... $ 112,161 $ 4,992 $ 88 $ 117,241
Operating income before income tax ..... 38,114 (510) (21,518) 16,086
----------
(1) Includes unallocated corporate expenses.
7. 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 certain interests in the Point Pedernales properties, have asserted
numerous causes of action including breach of contract, fraud and conspiracy in
connection with the plaintiff's allegation that: (i) royalties have not been
properly paid to them for production from the Point Pedernales field, (ii)
payments have not been made to them related to production from the Pescado and
Sacate field, and (iii) we have failed to recognize the plaintiff's interests in
the Tranquillon Ridge project. The plaintiffs have not specified damages. We
intend to vigorously contest these claims.
10
We have been named as a defendant in certain other lawsuits incidental
to our business. However, these actions and claims in the aggregate seek
substantial 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 the matters discussed above. 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 barrels of oil. Repairs were completed by the end of 1997, and production
recommenced in December 1997. The costs of the clean up and the cost to repair
the pipeline either have been or are expected to be covered by our insurance,
less a deductible of $0.1 million. As of March 31, 2002, we had received
insurance reimbursements of $4.2 million, with a remaining insurance receivable
of $0.5 million. We also have exposure to costs that may not be recoverable from
insurance, including certain fines, penalties, and damages and certain legal
fees. Such costs are not quantifiable at this time, but are not expected to be
material to our operating results, financial condition or liquidity.
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
(each a "Congo subsidiary") 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 income tax of a
foreign country without regard to the source of its income or on a residence
basis) utilized by the seller in years prior to the acquisitions if certain
triggering events occur, including (i) a disposition by either us or CMS of its
respective Congo subsidiary, (ii) either Congo subsidiary's sale of its interest
in the Yombo field, (iii) the acquisition of us or CMS by another consolidated
group or (iv) the failure of us or CMS's Congo subsidiary to continue as a
member of its respective consolidated group. A triggering event will not occur,
however, if a subsequent purchaser enters into certain agreements specified in
the consolidated return regulations intended to ensure that such dual
consolidated losses will not be claimed. The only time limit associated with the
occurrence of a triggering event relates to the utilization of a dual
consolidated loss in a foreign jurisdiction. A dual consolidated loss that is
utilized to offset income in a foreign jurisdiction is only subject to recapture
for 15 years following the year in which the dual consolidated loss was incurred
for U.S. income tax purposes. We and CMS have agreed 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 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 $56.2 million. We do not
expect a triggering event to occur with respect to us or CMS and do not believe
the agreement will have a material adverse effect upon us.
11
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
Our results of operations are significantly affected by fluctuations in
oil and gas prices. Success in acquiring oil and gas properties and our ability
to maintain or increase production through exploitation activities has also
significantly affected our operating results. The following table reflects our
production and average prices for oil and natural gas:
Quarter Ended March 31,
2000 2001
------------ ------------
Crude Oil and Liquids
Sales Volumes (MBbls/day)
Domestic .................. 41.5 43.7
Foreign ................... 5.0 2.8
------------ ------------
Total .................. 46.5 46.5
============ ============
Sales Prices ($/Bbl)
Unhedged .................. $ 15.82 $ 20.99
Hedged .................... 16.94 15.86
Revenues ($/thousands)
Domestic .................. $ 59,038 $ 83,168
Foreign ................... 7,651 6,039
Congo Earnout ............. (253) (1,047)
Marketing Fees ............ (194) (253)
Hedging ................... 4,683 (21,477)
------------ ------------
Total ................ $ 70,925 $ 66,430
============ ============
Natural Gas
Sales Volumes (MMcf/day)
Domestic .................. 36.2 42.5
============ ============
Sales Prices ($/Mcf)
Unhedged .................. $ 2.21 $ 13.26
Revenues ($/thousands)
Domestic .................. $ 7,289 $ 51,112
Marketing Fees ............ (88) (389)
------------ ------------
Total ................ $ 7,201 $ 50,723
============ ============
----------
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
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
12
QUARTER ENDED MARCH 31, 2002 COMPARED TO QUARTER ENDED MARCH 31, 2001
We had net income of $1.5 million, or $0.08 per diluted share for the
quarter ended March 31, 2002 as compared to net income of $9.6 million, or $0.57
per diluted share in the same period of 2001.
Revenues
Oil and Gas Revenues. Oil and gas revenues decreased 33% to $78.1
million for the quarter ended March 31, 2002 from $117.2 million in the same
period of 2001 due to significantly lower natural gas prices and lower
production which was partially offset by hedging gains in 2002. The realized oil
price in the first quarter of 2002 was $16.94 per Bbl, an increase of $1.08 per
Bbl from the same period in 2001. Oil production in the Congo increased 2.2
MBbls per day due to the favorable results of development drilling last year.
The increase was offset by a 2.2 MBbls per day decrease in domestic oil
production where production was lower from our thermal properties which is
continuing to rise in response to the resumption of steaming in the second half
of last year. We had hedging gains of $4.7 million in the first quarter of 2002
compared to a hedging loss of $21.5 million in same period of 2001. Natural gas
production averaged 36.2 MMcf per day in the first quarter of 2002, declining
15% from the 2001 period of 42.5 MMcf per day. The decline was primarily due to
lower domestic production onshore and offshore California. The first quarter
2002 realized natural gas price was $2.21 per Mcf, which decreased 83% from
$13.26 per Mcf in the prior year period.
Costs and Expenses
Costs and Expenses. Lease operating expenses ("LOE") for the quarter
ended March 31, 2002 totaled $38.1 million, as compared to $57.3 million for the
2001 period. The 34% decrease in LOE is principally due to lower steam and
workover costs in our California operations. Exploration costs were $1.1 million
in the quarter ended March 31, 2002, a decrease from $2.7 million in the same
period of 2001 which had $1.5 million of dry hole costs associated with our
exploratory well offshore the Republic of Ghana. Depreciation, depletion and
amortization ("DD&A") decreased to $19.2 million in first quarter of 2002
primarily due to lower gas production. The DD&A rate was $4.05 per BOE in the
2002 period compared to $4.07 per BOE in 2001. General and administrative
expense of $6.1 million in 2002 was $1.2 million lower than the comparable
period in 2001 due to lower headcount and the timing of expenses.
Derivative Gain (Loss). Our derivative loss for the quarter ended March
31, 2002 is comprised of a loss on our mark-to-market derivatives of $0.6
million and $0.1 million of ineffectiveness on our hedges.
Interest Expense. Interest expense of $9.0 million in the quarter ended
March 31, 2002 decreased 19% compared to interest expense of $11.1 million in
the same period of 2001. The decrease is primarily due to the benefit of our
interest rate swaps in 2002 of $1.9 million which more than offset higher
average borrowings.
Dividends. Dividends on the TECONS were $1.7 million in both quarters
ended March 31, 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 $1.0 million in the quarter
ended March 31, 2002 compared to an expense of $6.5 million in the prior year
period. Our effective income tax rate was 40.1% in 2002 and 40.3% in 2001.
CAPITAL RESOURCES AND LIQUIDITY
We have grown and diversified our operations through a series of
disciplined, low-cost 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 $12.3 million in the
quarter ended March 31, 2002. During that time period, we invested $15.4 million
in oil and gas properties and $1.0 million on gas plant and other facilities.
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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 $225 million borrowing
base under our Credit Agreement. Under the most restrictive covenant, $100
million is available at March 31, 2002 of which we had drawn $40.0 million under
the agreement. In late December 2001 and early January 2002, we entered into
interest rate swaps totaling $200 million; $150 million on our 9 3/8 % Notes and
$50 million on our 9 1/2% Notes.
CONTINGENCIES AND OTHER MATTERS
Legal Proceedings
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. Certain costs of repair and costs related to business
interruption are expected to be partially covered by insurance. We may have
exposure to costs that may not be recoverable from insurance, including those
associated with the repair of undamaged equipment. We resumed production in
January 2002.
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 may have exposure to costs that may not
be recoverable from insurance.
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, have asserted
numerous causes of action including breach of contract, fraud and conspiracy in
connection with the plaintiffs' allegation that: (i) royalties have not been
properly paid to them for production from the Point Pedernales field, (ii)
payments have not been made to them related to production from the Pescado and
Sacate fields and (iii) we have failed to recognize the plaintiffs' interests in
the Tranquillon Ridge project. The plaintiffs have not specified damages. We
intend to vigorously contest these claims.
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 own a 50% interest in the Sacate
field, offshore Santa Barbara County, California. We have alleged that by
grossly inflating the fee that ExxonMobil insists we must pay to use an existing
ExxonMobil platform and production infrastructure, ExxonMobil failed to submit a
proposal for the development of the Sacate field consistent with the unit
operating agreement. We, therefore believe that we have been denied a reasonable
opportunity to exercise our rights under the unit operating agreement. We have
alleged that ExxonMobil's actions breach the unit operating agreement and the
covenant of good faith and fair dealing. We are seeking damages and a
declaratory judgment as to the payment that must be made to access ExxonMobil's
platform and facilities.
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 substantial
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
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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 December 31, 2001, we had received insurance reimbursements of
$4.2 million, with a remaining insurance receivable of $0.5 million. We also
have exposure to costs that may not be recoverable from insurance, including
certain fines, penalties, and damages and certain legal fees. Such costs are not
quantifiable at this time, but are not expected to be material to our operating
results, financial condition or liquidity.
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 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. We do not
expect a triggering event to occur with respect to us or CMS and do not believe
the agreement will have a material adverse effect upon us.
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.
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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, and the related asset value is increased by the amount of the resulting
liability. 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.
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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.
There are no material changes in our quantitative and qualitative
disclosures about market risks from those reported in our Annual Report on Form
10-K for the year ended December 31, 2001.
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PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Part I, Item 1, Financial Statements, Note 7, 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
None.
(b) REPORTS ON FORM 8-K:
None.
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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: May 15, 2002 By: /s/ James L. Payne
------------------ --------------------------------
James L. Payne
Chairman, President and
Chief Executive Officer
Date: May 15, 2002 By: /s/ Janet F. Clark
------------------ --------------------------------
Janet F. Clark
Senior Vice President and
Chief Financial Officer
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