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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 JUNE 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
August 8, 2002: 17,188,623.
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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.................................................. 14
Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation Reform Act of 1995......... 20
Item 3. Quantitative and Qualitative Disclosures About Market Risk........................ 20
PART II
Item 1. Legal Proceedings................................................................. 21
Item 2. Changes in Securities and Use of Proceeds......................................... 21
Item 3. Defaults Upon Senior Securities................................................... 21
Item 4. Submission of Matters to a Vote of Security-Holders............................... 21
Item 5. Other Information................................................................. 21
Item 6. Exhibits and Reports on Form 8-K.................................................. 21
Signatures ....................................................................... 22
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 Six Months Ended
June 30, June 30,
----------------------------- --------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
Revenues
Crude oil and liquids ................................... $ 75,735 $ 65,419 $ 145,936 $ 130,611
Natural gas ............................................. 8,340 32,598 14,754 80,980
Other ................................................... 42 27 48 115
------------ ------------ ------------ ------------
84,117 98,044 160,738 211,706
------------ ------------ ------------ ------------
Costs and Expenses
Lease operating expenses ................................ 34,955 48,685 72,631 105,573
Exploration costs ....................................... 424 4,502 1,482 7,167
Depletion, depreciation and amortization ................ 18,636 19,984 37,004 38,807
Impairment of oil and gas properties .................... -- 880 -- 880
General and administrative .............................. 7,232 9,229 13,315 16,505
Other ................................................... (222) 97 (197) 1,890
Loss (gain) on disposition of properties ................ (15,326) (198) (15,326) 131
------------ ------------ ------------ ------------
45,699 83,179 108,909 170,953
------------ ------------ ------------ ------------
Income From Operations ....................................... 38,418 14,865 51,829 40,753
Derivative gain (loss) .................................. (177) 4 (933) (3)
Interest income ......................................... 66 214 174 831
Interest expense ........................................ (9,212) (10,449) (18,216) (21,584)
Dividends on TECONS ..................................... (1,653) (1,653) (3,306) (3,306)
------------ ------------ ------------ ------------
Income from Continuing Operations Before Income Tax .......... 27,442 2,981 29,548 16,691
Income tax expense (benefit)
Current ................................................. -- (535) -- 81
Deferred ................................................ 11,126 1,735 11,970 6,644
------------ ------------ ------------ ------------
11,126 1,200 11,970 6,725
------------ ------------ ------------ ------------
Net Income From Continuing Operations ........................ 16,316 1,781 17,578 9,966
Income from discontinued operations, including loss on
disposition, net of income taxes ..................... 250 878 450 2,296
------------ ------------ ------------ ------------
Net Income ................................................... $ 16,566 $ 2,659 $ 18,028 $ 12,262
============ ============ ============ ============
Earnings Per Share
Basic
Net income from continuing operations ................ $ 0.96 $ 0.11 $ 1.03 $ 0.60
============ ============ ============ ============
Net income ........................................... $ 0.97 $ 0.16 $ 1.06 $ 0.74
============ ============ ============ ============
Diluted
Net income from continuing operations ................ $ 0.95 $ 0.09 $ 1.02 $ 0.57
============ ============ ============ ============
Net income ........................................... $ 0.96 $ 0.14 $ 1.05 $ 0.71
============ ============ ============ ============
Weighted Average Shares Outstanding
Basic ................................................... 17,079 16,645 17,040 16,589
============ ============ ============ ============
Diluted ................................................. 17,291 17,152 17,237 17,078
============ ============ ============ ============
See accompanying notes.
3
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)
June 30, December 31,
2002 2001
----------- -----------
(UNAUDITED)
ASSETS
Current assets
Cash and cash equivalents ....................................................... $ 245 $ 7,110
Accounts receivable, net ........................................................ 44,502 48,304
Inventory ....................................................................... 4,902 3,839
Assets held for sale ............................................................ 1,657 819
Assets from price risk management activities .................................... 662 19,610
Prepaid expenses and other ...................................................... 5,570 2,050
----------- -----------
Total current assets ......................................................... 57,538 81,732
----------- -----------
Property and equipment, at cost
Oil and gas properties (successful efforts method) .............................. 915,737 1,014,429
Land ............................................................................ 57,563 55,859
Gas plant facilities ............................................................ 8,723 8,723
Other property .................................................................. 10,867 10,365
----------- -----------
992,890 1,089,376
Accumulated depletion, depreciation and amortization ............................ (347,127) (424,837)
----------- -----------
Total property and equipment, net ............................................ 645,763 664,539
----------- -----------
Deferred tax assets, net ............................................................ 61,732 70,013
Other assets ........................................................................ 28,698 23,528
----------- -----------
Total assets .............................................................. $ 793,731 $ 839,812
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable ................................................................ $ 23,207 $ 35,771
Accrued interest ................................................................ 4,089 5,635
Other accrued liabilities ....................................................... 46,722 57,718
----------- -----------
Total current liabilities .................................................... 74,018 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 ............................................................. 8,800 41,500
Interest rate swaps - fair value adjustment ..................................... 4,930 (633)
----------- -----------
Total long-term debt ......................................................... 423,307 450,444
----------- -----------
Other long-term liabilities ......................................................... 16,720 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 21,034,880 in
2002 and 20,905,796 in 2001 .................................................. 210 209
Additional paid-in capital ...................................................... 367,701 366,792
Treasury stock (at cost) 3,874,417 shares in 2002 and 3,902,721 shares in 2001 .. (75,768) (75,855)
Stock held by benefit trust, 63,869 shares in 2002 and 122,995 shares in 2001 ... (1,040) (2,919)
Deferred stock compensation ..................................................... (886) (902)
Accumulated other comprehensive income (loss) ................................... (4,606) 11,534
Accumulated deficit ............................................................. (120,925) (138,952)
----------- -----------
Total stockholders' equity ................................................... 164,686 159,907
----------- -----------
Total liabilities and stockholders' equity ................................ $ 793,731 $ 839,812
=========== ===========
See accompanying notes.
4
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
Quarter Ended Six Months Ended
June 30, June 30,
-------------------------- --------------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------
Cash flows from operating activities
Net income ............................................... $ 16,566 $ 2,659 $ 18,028 $ 12,262
Adjustments to reconcile net income to net cash provided
by operating activities
Depletion, depreciation and amortization............... 18,636 19,984 37,004 38,807
Dry hole costs......................................... -- 504 61 1,986
Impairment of oil and gas properties................... -- 880 -- 880
Amortization of debt financing costs................... 664 599 1,266 1,195
Loss (gain) on disposition of properties............... (15,326) (198) (15,326) 131
Deferred income taxes.................................. 11,126 1,735 11,970 6,644
Non-cash effect of discontinued operations............. 1,159 931 2,083 2,749
Other.................................................. 407 (711) 1,234 319
----------- ----------- ----------- -----------
33,232 26,383 56,320 64,973
Working capital and other changes, net of non-cash
transactions
Accounts receivable.................................... 40 15,565 3,806 1,185
Accounts payable....................................... (13,850) 1,211 (28,051) 20,418
Other.................................................. (2,737) (8,218) (3,068) (20,225)
----------- ----------- ----------- -----------
Net cash provided by operating activities........... 16,685 34,941 29,007 66,351
----------- ----------- ----------- -----------
Cash flows from investing activities
Additions to oil and gas properties....................... (12,991) (47,028) (28,345) (70,034)
Acquisitions of oil and gas properties.................... -- -- -- (32,705)
Additions to gas plants and other facilities.............. (1,193) (5,265) (2,206) (1,382)
Proceeds from sale of properties.......................... 24,856 -- 24,856 --
----------- ----------- ----------- -----------
Net cash provided by (used in) investing activities. 10,672 (52,293) (5,695) (104,121)
----------- ----------- ----------- -----------
Cash flows from financing activities
Debt issuance and modification costs...................... -- -- -- (97)
Payments of long-term debt................................ -- -- -- (25)
Net repayments of credit facility......................... (31,175) -- (32,700) --
Proceeds from exercise of stock options................... 470 3,623 1,229 3,623
Purchase of treasury shares............................... -- -- -- (2,085)
Other proceeds........................................... 1,294 -- 1,294 --
----------- ----------- ----------- -----------
Net cash provided by(used in) financing activities.. (29,411) 3,623 (30,177) 1,416
----------- ----------- ----------- -----------
Decrease in cash and cash equivalents....................... (2,054) (13,729) (6,865) (36,354)
Cash and cash equivalents
Beginning of period.................................... 2,299 16,822 7,110 39,447
----------- ----------- ----------- -----------
End of period.......................................... $ 245 $ 3,093 $ 245 $ 3,093
=========== =========== =========== ===========
See accompanying notes.
5
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(IN THOUSANDS)
(UNAUDITED)
Quarter Ended Six Months Ended
June 30, June 30,
------------------------ ------------------------
2002 2001 2002 2001
---------- ---------- ---------- ----------
Net income ................................................. $ 16,566 $ 2,659 $ 18,028 $ 12,262
Other comprehensive income, net of tax:
Cumulative-effect transition adjustment .............. -- -- -- (15,976)
Reclassification adjustment for settled contracts .... 1,195 11,577 (1,601) 22,558
Net change in fair value of derivative instruments ... (2,829) (3,545) (14,539) (13,742)
---------- ---------- ---------- ----------
Other comprehensive income (loss) ............... (1,634) 8,032 (16,140) (7,160)
---------- ---------- ---------- ----------
Comprehensive income ................................. $ 14,932 $ 10,691 $ 1,888 $ 5,102
========== ========== ========== ==========
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 June 30,
2002, and for the quarters and six months ended June 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 it had no impact on our financial statements. At June 30, 2002, we
presented certain property dispositions as discontinued operations in accordance
with SFAS No. 144. (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, 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.
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. We are currently evaluating the effects of this pronouncement.
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. We are currently evaluating the effects of
this pronouncement.
7
2. DISCONTINUED OPERATIONS
During the second quarter of 2002, we sold a majority of our oil and
gas properties located in Texas, Alabama and Louisiana (Eastern properties) for
approximately $7.4 million and entered into a letter of intent to sell the
remaining Eastern properties. We recognized a $0.1 million loss on the sale of
these properties. Historical results of operations from these properties and the
loss on sale are classified as discontinued operations in our statements of
income. At June 30, 2002, the remaining Eastern properties that we intend to
sell were reclassified to assets held for sale and are carried at the lower of
cost or net realizable value.
3. RESTRUCTURING 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 June 30,
2001 2002 2002
--------------- --------------- ---------------
(In thousands)
Severance, benefits and other ..... $ 1,675 $ 1,493 $ 182
Contract termination .............. 2,681 2,626 55
--------------- --------------- ---------------
$ 4,356 $ 4,119 $ 237
=============== =============== ===============
We expect that the balance of the restructuring liability will be paid
during 2002.
4. 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 June 30,
-----------------------------------------------------------------------------
2002 2001
------------------------------------- -------------------------------------
Net Per Net Per
Income Shares Share Income Shares Share
---------- ---------- ---------- ---------- ---------- ----------
Basic Earnings Per Share (In thousands, except per share data)
Income from continuing
operations ................... $ 16,316 17,079 $ 0.96 $ 1,781 16,645 $ 0.11
========== ========== ----------
Income from discontinued
operations ................... 250 17,079 0.01 878 16,645 0.05
---------- ========== ---------- ---------- ========== ----------
Net income per common share ............ $ 16,566 17,079 $ 0.97 $ 2,659 16,645 $ 0.16
========== ========== ========== ========== ========== ==========
Diluted Earnings Per Share
Income from continuing
operations ................... $ 16,316 17,079 $ 1,781 16,645
Effect of dilutive securities
Stock options and restricted
stock ...................... 149 338
Shares held by benefit trust ... 29 63 (217) 169
---------- ---------- ---------- ----------
Net income from continuing
operations available to
common stockholders and
assumed conversions ........ 16,345 17,291 0.95 1,564 17,152 0.09
========== ==========
Income from discontinued
operations ................... 250 17,291 0.01 878 17,152 0.05
---------- ========== ---------- ---------- ========== ----------
Net income per common share ...... $ 16,595 17,291 $ 0.96 $ 2,442 17,152 $ 0.14
========== ========== ========== ========== ========== ==========
8
Year to Date Ended June 30,
-----------------------------------------------------------------------------
2002 2001
------------------------------------- -------------------------------------
Net Per Net Per
Income Shares Share Income Shares Share
---------- ---------- ---------- ---------- ---------- ----------
(In thousands, except per share data)
Basic Earnings Per Share
Income from continuing
operations ................... $ 17,578 17,040 $ 1.03 $ 9,966 16,589 $ 0.60
=========== ==========
Income from discontinued
operations ................... 450 17,040 0.03 2,296 16,589 0.14
---------- ========== ---------- ---------- ========== ----------
Net income per common share ............ $ 18,028 17,040 $ 1.06 $ 12,262 16,589 $ 0.74
========== ========== ========== ========== ========== ==========
Diluted Earnings Per Share
Income from continuing
operations ................... $ 17,578 17,040 $ 9,966 16,589
Effect of dilutive securities
Stock options and restricted
stock ...................... 139 316
Shares held by benefit trust ... (8) 58 (170) 173
---------- ---------- ---------- ----------
Net income from continuing
operations available to
common stockholders and
assumed conversions ........ 17,570 17,237 1.02 9,796 17,078 0.57
========== ==========
Income from discontinued
operations ................... 450 17,237 0.03 2,296 17,078 0.14
---------- ========== ---------- ---------- ========== ----------
Net income per common share ...... $ 18,020 17,237 $ 1.05 $ 12,092 17,078 $ 0.71
========== ========== ========== ========== ========== ==========
5. LONG-TERM DEBT
Our long-term debt consisted of the following:
June 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 (3.79% on June 30, 2002 and 3.71% on
December 31, 2001) .......................................... 8,800 41,500
------------ ------------
Total debt ............................................. 418,377 451,077
Interest rate swaps - fair value adjustment (Note 6) ............ 4,930 (633)
------------ ------------
Long-term debt .................................................. $ 423,307 $ 450,444
============ ============
6. 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.
9
Derivative Instruments Designated as Cash Flow Hedges.
At June 30, 2002, we had entered into the following cash flow hedges:
WTI
Barrels Per Average
Day Price / Bbl
-------------- --------------
Swaps
Third quarter 2002 ..................... 18,500 $ 24.73
Fourth quarter 2002 .................... 20,000 24.87
First quarter 2003 ..................... 13,000 24.20
Second quarter 2003 .................... 12,000 23.86
Third quarter 2003 ..................... 10,000 23.49
Fourth quarter 2003..................... 8,000 23.34
First quarter 2004...................... 4,000 23.53
Put Options
Third quarter 2002 ..................... 9,000 22.00
Fourth quarter 2002 .................... 9,000 22.00
Subsequent to June 30, 2002, we entered into the following cash flow
hedges:
WTI
Barrels Per Average
Day Price / Bbl
-------------- --------------
Swaps
First quarter 2003 ..................... 2,000 $ 25.70
Third quarter 2003 ..................... 1,000 24.50
Fourth quarter 2003 .................... 1,000 24.03
First quarter 2004...................... 3,000 23.75
We recorded a loss of $2.2 million related to our settled swaps in the
second quarter of 2002. During the quarter ended June 30, 2002, our put options
on 14,000 WTI Bbls/day expired and we recorded a loss of $1.5 million which is
reflected in our statements of income as a reduction of revenue.
Derivative Instruments Designated as Fair Value Hedges
We have 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. These swaps are designated
as fair value hedges and are reflected as an increase of long-term debt of $4.9
million as of June 30, 2002, with a corresponding increase in other long-term
assets. During the six months ended June 30, 2002, we recognized $3.7 million as
a reduction of interest expense. 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%.
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 second
quarter, $1.3 million was reclassified into earnings and at June
10
30, 2002, a deferred gain of $1.4 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 June 2002, we sold our bankruptcy claim 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 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 call spread with Enron was cancelled. 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 value of the
call spread decreased during the quarter ended June 30, 2002, and we recorded a
loss of $0.2 million. At June 30, 2002, $1.9 million is reflected in other
long-term liabilities.
7. 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 June 30, 2002
-------------------------------------------------------------------
Oil and Gas Oil and Gas
Domestic International Other(1) Total
-------------- -------------- -------------- --------------
Revenues from external customers ....... $ 75,831 $ 8,244 $ 42 $ 84,117
Operating income before income tax ..... 42,293 3,800 (18,651) 27,442
For the Quarter Ended June 30, 2001
------------------------------------------------------------------
Oil and Gas Oil and Gas
Domestic International Other(1) Total
-------------- -------------- -------------- --------------
Revenues from external customers ....... $ 89,291 $ 8,726 $ 27 $ 98,044
Operating income before income tax ..... 19,232 4,703 (20,954) 2,981
For the Six Months Ended June 30, 2002
------------------------------------------------------------------
Oil and Gas Oil and Gas
Domestic International Other(1) Total
-------------- -------------- -------------- --------------
Revenues from external customers ....... $ 145,022 $ 15,668 $ 48 $ 160,738
Operating income before income tax ..... 60,085 6,144 (36,681) 29,548
For the Six Months Ended June 30, 2001
------------------------------------------------------------------
Oil and Gas Oil and Gas
Domestic International Other(1) Total
-------------- -------------- -------------- --------------
Revenues from external customers ....... $ 197,865 $ 13,726 $ 115 $ 211,706
Operating income before income tax ..... 54,970 4,193 (42,472) 16,691
---------------
(1) Includes unallocated corporate expenses.
8. 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 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
11
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 actions breach 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 gain
related to the sale of this unproved property.
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 June 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 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.
12
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 $56.2 million. During the
second quarter of 2002, we were notified by CMS that they have entered into an
agreement to sell their interest in the Yombo field offshore Congo and that the
transaction will be structured to avoid a triggering event.
13
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
Our results of operations are significantly affected by fluctuations
in oil and gas prices. Success in acquiring oil and gas properties and our
ability to maintain or increase production through exploitation activities has
also significantly affected our operating results. We sold our properties
located in Texas, Louisiana and Alabama (Eastern properties) during the second
quarter of 2002 and reflected the Eastern properties as discontinued operations
in our financial statements. The following table reflects our production and
average prices for oil and natural gas excluding the Eastern properties for all
periods presented:
Quarter Ended Six Months Ended
June 30, June 30,
---------------------------------- ----------------------------------
2002 2001 2002 2001
--------------- --------------- --------------- ---------------
Crude Oil and Liquids
Sales Volumes (MBbls/day)
Domestic .................... 39.4 40.6 40.2 41.9
International ............... 5.4 5.9 5.2 4.4
--------------- --------------- --------------- ---------------
Total .................... 44.8 46.5 45.4 46.3
=============== =============== =============== ===============
Sales Prices ($/Bbl)
Unhedged .................... $ 19.13 $ 20.04 $ 17.45 $ 20.48
Hedged ...................... 18.60 15.46 17.76 15.60
Revenues ($/thousands)
Domestic .................... $ 69,904 $ 76,332 $ 128,191 $ 158,255
International
9,686 9,797 17,364 15,844
Congo Earnout
(1,442) (1,071) (1,696) (2,118)
Marketing Fees
(253) (249) (446) (503)
Hedging ..................... (2,160) (19,390) 2,523 (40,867)
--------------- --------------- --------------- ---------------
Total .................. $ 75,735 $ 65,419 $ 145,936 $ 130,611
=============== =============== =============== ===============
Natural Gas
Sales Volumes (MMcf/day)
Domestic .................... 31.3 29.1 31.8 33.2
=============== =============== =============== ===============
Sales Prices ($/Mcf)
Unhedged .................... $ 2.93 $ 12.32 $ 2.57 $ 13.46
Revenues ($/thousands)
Domestic .................... $ 8,489 $ 32,905 $ 14,991 $ 81,676
Marketing Fees .............. (149) (307) (237) (696)
--------------- --------------- --------------- ---------------
Total .................. $ 8,340 $ 32,598 $ 14,754 $ 80,980
=============== =============== =============== ===============
-------------------
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
14
QUARTER ENDED JUNE 30, 2002 COMPARED TO QUARTER ENDED JUNE 30, 2001
We had net income of $16.6 million, or $0.96 per diluted share for the
quarter ended June 30, 2002 as compared to net income of $2.7 million, or $0.14
per diluted share in the same period of 2001. Our net income for the quarter
ended June 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 $7.8 million, or $0.46 per diluted share.
Revenues
Oil and Gas Revenues. Oil and gas revenues of $84.1 million for the
quarter ended June 30, 2002 decreased 14% from $98.0 million in the same period
of 2001 due to significantly lower natural gas prices and lower oil production
which was partially offset by lower hedging losses in 2002. The realized oil
price in the second quarter of 2002 was $18.60 per Bbl, an increase of $3.14 per
Bbl from the same period in 2001. Crude oil production averaged 44.8 MBbls/day
in the second quarter 2002, a decrease of 4% from the same period in 2001. Lower
production from our California properties was due to downtime at Cymric and
Point Pedernales fields which were partially offset by increased production due
to re-steaming at Belridge and Midway-Sunset. We had a hedging loss of $2.2
million in the second quarter of 2002 compared to a hedging loss of $19.4
million in same period of 2001. Natural gas production averaged 31.3 MMcf per
day in the second quarter of 2002, an increase of 8% from the 2001 period of
29.1 MMcf per day primarily due to increased production onshore California. The
second quarter 2002 realized natural gas price was $2.93 per Mcf, which
decreased 76% from $12.32 per Mcf in the prior year period.
Costs and Expenses
Costs and Expenses. Lease operating expenses ("LOE") for the quarter
ended June 30, 2002 decreased 28% to $35.0 million from $48.7 million for the
2001 period principally due to lower steam and workover costs in our California
operations. Excluding the steam component, LOE decreased 11% in the second
quarter of 2002 compared to the same period of 2001. Exploration costs were $0.4
million in the quarter ended June 30, 2002, a decrease from $4.5 million in the
same period of 2001 which had $2.6 million for the acquisition of seismic and
$0.9 million related to new ventures. Depreciation, depletion and amortization
("DD&A") decreased to $18.6 million in second quarter of 2002 primarily due to a
lower DD&A rate and lower oil production. The DD&A rate was $4.10 per BOE in the
2002 period compared to $4.28 per BOE in 2001. General and administrative
expense of $7.2 million in 2002 was $2.0 million lower than the comparable
period in 2001 which had $1.7 million in severance 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 quarter ended June
30, 2002 is comprised of a loss on our mark-to-market derivatives of $0.2
million.
Interest Expense. Interest expense of $9.2 million in the quarter ended
June 30, 2002 decreased 12% compared to interest expense of $10.4 million in the
same period of 2001. The decrease is primarily due to the benefit of our
interest rate swaps in 2002 of $1.8 million.
Dividends. Dividends on the TECONS were $1.7 million in both quarters
ended June 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 $11.1 million in the quarter
ended June 30, 2002 compared to an expense of $1.2 million in the prior year
period. Our effective income tax rate was 40.5% in 2002 and 40.3% in 2001.
15
YEAR TO DATE JUNE 30, 2002 COMPARED TO YEAR TO DATE JUNE 30, 2001
We had net income of $18.0 million, or $1.05 per diluted share for six
months ended June 30, 2002 as compared to net income of $12.3 million, or $0.71
per diluted share in the same period of 2001. Excluding the gain from the
settlement with ExxonMobil mentioned above, our net income for the 2002 period
was $9.3 million, or $0.55 per share.
Revenues
Oil and Gas Revenues. Oil and gas revenues decreased 24% to $160.7
million for the six months ended June 30, 2002 from $211.7 million in the same
period of 2001 due to significantly lower realized natural gas prices and lower
production which was partially offset by hedging gains in 2002. Crude oil
production averaged 45.4 MBbls/day for the six months ended June 30, 2002, a
decrease of 2% from the same period of 2001 primarily due to lower production
offshore California due to mechanical downtime. The realized oil price for the
six months ended June 30, 2002 was $17.76 per Bbl, an increase of $2.16 per Bbl
from the same period in 2001. We had hedging gains of $2.5 million in the six
months ended June 30, 2002 compared to a hedging loss of $40.9 million in same
period of 2001. Natural gas production averaged 31.8 MMcf per day for the six
months ended June 30, 2002, declining 4% from the 2001 period of 33.2 MMcf per
day. The decline was primarily due to lower domestic production onshore and
offshore California. The realized natural gas price for the six months ended
June 30, 2002 was $2.57 per Mcf, which decreased 81% from $13.46 per Mcf in the
comparable period in 2001.
Costs and Expenses
Costs and Expenses. LOE for the six months ended June 30, 2002 totaled
$72.6 million, as compared to $105.6 million for the 2001 period. The 31%
decrease in LOE is principally due to lower steam and workover costs in our
California operations. Exploration costs were $1.5 million in the six months
ended June 30, 2002, a decrease from $7.2 million in the same period of 2001
which had $2.5 million in seismic acquisitions and $1.5 million of dry hole
costs associated with our exploratory well offshore the Republic of Ghana. DD&A
decreased to $37.0 million for the six months ended June 30, 2002 primarily due
to lower gas production. The DD&A rate was $4.03 per BOE in the 2002 period
compared to $4.14 per BOE in 2001. General and administrative expense of $13.3
million in 2002 was $3.2 million lower than the comparable period in 2001 due to
a $1.7 million severance payment in 2001 and lower 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 six months ended
June 30, 2002 is comprised of a loss on our mark-to-market derivatives of $0.8
million and $0.1 million of ineffectiveness on our hedges.
Interest Expense. Interest expense of $18.2 million for the six months
ended June 30, 2002 decreased 16% compared to interest expense of $21.6 million
in the same period of 2001. The decrease is primarily due to the benefit of our
interest rate swaps in 2002 of $3.8 million which more than offset higher
average borrowings.
Dividends. Dividends on the TECONS were $3.3 million in both the six
months ended June 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 $12.0 million for the six
months ended June 30, 2002 compared to an expense of $6.7 million in the prior
year period. Our effective income tax rate was 40.5% in 2002 and 40.3% in 2001.
16
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 $29.0 million for the six
months ended June 30, 2002 and $28.3 million was invested in oil and gas
properties and $2.2 million on gas plant and other facilities. We also received
$24.9 million in proceeds from the sale of properties in the six months ended
June 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, $128
million was available at June 30, 2002 of which we had drawn $8.8 million under
the agreement. We have 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
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. 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 on these 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 twelve 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, 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. We settled all issues associated with 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 actions breach 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
17
relinquished our right to participate in the Sacate field and recorded a $14.7
million 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 June 30, 2002, we had received
insurance reimbursements of $4.2 million, with a remaining insurance receivable
of $0.5 million. 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 will be structured to avoid a triggering event.
18
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, 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.
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.
We are currently evaluating the effects of this pronouncement.
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. We are currently evaluating the effects of
this pronouncement.
19
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.
20
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Part I, Item 1, Financial Statements, Note 8, 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
We held our Annual Meeting of Stockholders on May 22, 2002. The
following Directors were elected with the following voting results:
For Withheld
--------------------------- ---------------------------
Isaac Arnold, Jr. 14,943,850 117,835
David H. Batchelder 14,944,169 117,516
Charles M. Elson 14,944,169 117,516
Robert L. Gerry III 14,944,169 117,516
James T. Jongebloed 14,837,169 224,516
James L. Payne 14,944,169 117,516
Gary R. Petersen 14,842,969 218,716
Sheryl K. Pressler 14,837,169 224,516
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) EXHIBITS
99.1 Certification with respect to quarterly report of Nuevo Energy
Company.
(b) REPORTS ON FORM 8-K:
o We filed a current report on Form 8-K on July 22, 2002 announcing
a change in our independent auditors.
21
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: August 14, 2002 By: /s/ James L. Payne
--------------------------- --------------------------------
James L. Payne
Chairman, President and
Chief Executive Officer
Date: August 14, 2002 By: /s/ Janet F. Clark
--------------------------- --------------------------------
Janet F. Clark
Senior Vice President and
Chief Financial Officer
22
EXHIBIT INDEX
Exhibit Number Description
-------------- -----------
99.1 Certification with respect to Quarterly Report of Nuevo
Energy Company