EXHIBIT 99.1
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
Page
----
Independent Auditors' Report............................................... 2
Financial Statements:
Consolidated Statements of Income for the Years Ended
December 31, 2001, 2000 and 1999.......................................... 3
Consolidated Balance Sheets as of
December 31, 2001 and 2000................................................ 4
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2001, 2000 and 1999.......................................... 5
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 2001, 2000 and 1999.......................................... 6
Consolidated Statements of Comprehensive Income and
Changes in Accumulated Other Comprehensive Income
for the Years Ended December 31, 2001, 2000 and 1999...................... 7
Notes to the Consolidated Financial Statements............................. 8
1
INDEPENDENT AUDITORS' REPORT
----------------------------
The Board of Directors
Nuevo Energy Company and Subsidiaries:
We have audited the accompanying consolidated balance sheet of Nuevo Energy
Company and subsidiaries as of December 31, 2001 and 2000, and the related
consolidated statements of income, cash flows, stockholders' equity and
comprehensive income and changes in accumulated other comprehensive income for
each of the years in the three-year period ended December 31, 2001. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Nuevo Energy Company
and subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 2001, in conformity with accounting principles generally
accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, effective
January 1, 2000, the Company changed its method of accounting for its processed
fuel oil and natural gas liquids inventories. Also discussed in Note 2,
effective January 1, 2001, the Company changed its method of accounting for
derivative instruments.
KPMG LLP
November 11, 2002
2
NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per share data)
Year Ended December 31,
-----------------------------
2001 2000 1999
--------- -------- --------
Revenues
Crude oil and liquids......................... 262,452 252,493 195,195
Natural gas................................... 82,587 54,368 30,501
Other......................................... 273 2,358 4,778
--------- -------- --------
345,312 309,219 230,474
--------- -------- --------
Costs and Expenses
Lease operating expenses...................... 175,114 144,312 124,196
Exploration costs............................. 22,058 9,774 14,017
Depletion, depreciation and amortization...... 74,000 61,511 72,988
Impairment of oil and gas properties.......... 103,490 -- --
General and administrative.................... 36,904 32,974 32,266
Restructuring and severance charges........... 4,859 -- --
Loss on assets held for sale.................. 3,494 -- --
Other......................................... 14,928 5,103 8,945
Gain on disposition of properties............. (882) (657) (85,294)
--------- -------- --------
433,965 253,017 167,118
--------- -------- --------
Income (Loss) From Operations................... (88,653) 56,202 63,356
Derivative gain............................... 226 -- --
Interest income............................... 1,311 1,935 2,857
Interest expense.............................. (43,006) (37,472) (33,110)
Dividends on TECONS........................... (6,613) (6,613) (6,613)
--------- -------- --------
Income (Loss) From Continuing Operations
Before Income Tax............................. (136,735) 14,052 26,490
Income tax expense (benefit)
Current....................................... -- (371) 1,200
Deferred...................................... (54,804) 6,034 (6,395)
--------- -------- --------
(54,804) 5,663 (5,195)
--------- -------- --------
Income (Loss) From Continuing Operations........ (81,931) 8,389 31,685
Income (Loss) from discontinued operations,
net of income taxes........................... 2,760 4,042 (243)
Cumulative effect of change in accounting
principle, net of income tax benefit of $537.. -- (796) --
--------- -------- --------
Net Income (Loss)............................... (79,171) 11,635 31,442
========= ======== ========
Earnings Per Share
Basic
Income (loss) from continuing operations...... $ (4.90) $ 0.48 $ 1.64
Income (loss) from discontinued operations,
net of income taxes......................... 0.17 0.23 (0.02)
Cumulative effect of a change in accounting
principle, net of income tax benefit......... -- (0.04) --
--------- -------- --------
Net income (loss)............................. $ (4.73) $ 0.67 $ 1.62
========= ======== ========
Diluted
Income (loss) from continuing operations...... $ (4.90) $ 0.46 $ 1.63
Income (loss) from discontinued operations,
net of income taxes......................... 0.17 0.22 (0.02)
Cumulative effect of a change in accounting
principle, net of income tax benefit........ -- (0.04) --
--------- -------- --------
Net income (loss)............................. $ (4.73) $ 0.64 $ 1.61
========= ======== ========
Weighted Average Shares Outstanding
Basic......................................... 16,735 17,447 19,353
========= ======== ========
Diluted....................................... 16,735 17,941 19,507
========= ======== ========
See accompanying notes.
3
NUEVO ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
December 31,
----------------------
2001 2000
---------- ----------
ASSETS
Current assets
Cash and cash equivalents............................ $ 7,110 $ 39,447
Accounts receivable, net of allowance of $1,280 in
2001 and $766 in 2000............................... 48,304 71,777
Inventory............................................ 3,839 4,546
Assets held for sale................................. 819 --
Assets from price risk management activities......... 19,610 --
Prepaid expenses and other........................... 2,050 2,726
---------- ----------
Total current assets............................... 81,732 118,496
---------- ----------
Property and equipment, at cost
Land................................................. 55,859 53,246
Oil and gas properties (successful efforts method)... 1,014,429 1,102,233
Gas plant facilities................................. 8,723 12,020
Other facilities..................................... 11,347 12,907
---------- ----------
1,090,358 1,180,406
Accumulated depreciation, depletion and
amortization........................................ (424,837) (496,444)
---------- ----------
Total property and equipment, net.................. 665,521 683,962
---------- ----------
Deferred tax assets, net............................... 70,013 16,282
Other assets........................................... 22,546 29,284
---------- ----------
Total assets....................................... $ 839,812 $ 848,024
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable..................................... $ 35,771 $ 25,895
Accrued interest..................................... 5,635 5,757
Accrued drilling costs............................... 15,081 12,467
Accrued lease operating costs........................ 23,244 30,037
Deferred income tax.................................. 7,783 --
Other accrued liabilities............................ 11,610 17,668
---------- ----------
Total current liabilities.......................... 99,124 91,824
---------- ----------
Long-term debt (Note 12)............................... 450,444 409,727
Other long-term liabilities............................ 15,337 8,356
Company-Obligated Mandatorily Redeemable Convertible
Preferred Securities of Nuevo Financing I............. 115,000 115,000
Commitments and contingencies (Note 15)
Stockholders' equity
Preferred stock, $1.00 par value, 10,000,000 shares
authorized; 7% Cumulative Convertible Preferred
Stock, none issued and outstanding at December 31,
2001 and 2000....................................... -- --
Common stock, $0.01 par value, 50,000,000 shares
authorized, 20,905,796 and 20,620,296 shares issued
and 16,880,080 and 16,632,318 shares outstanding at
December 31, 2001 and 2000.......................... 209 206
Additional paid-in capital........................... 366,792 361,643
Treasury stock, at cost, 3,902,721 and 3,813,074
shares, at December 31, 2001 and 2000............... (75,855) (74,703)
Stock held by benefit trust, 122,995 and 174,904
shares, at December 31, 2001 and 2000............... (2,919) (3,646)
Deferred stock compensation.......................... (902) (602)
Accumulated other comprehensive income............... 11,534 --
Accumulated deficit.................................. (138,952) (59,781)
---------- ----------
Total stockholders' equity......................... 159,907 223,117
---------- ----------
Total liabilities and stockholders' equity....... $ 839,812 $ 848,024
========== ==========
See accompanying notes.
4
NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Year Ended December 31,
-------------------------------
2001 2000 1999
--------- --------- ---------
Cash flows from operating activities
Net income (loss)............................ $ (79,171) $ 11,635 $ 31,442
Adjustments to reconcile net income (loss) to
net cash provided by operating activities
Cumulative effect of a change in accounting
principle, net of income taxes............. -- 796 --
Depreciation, depletion and amortization.... 74,000 61,511 72,988
Dry hole costs.............................. 14,138 2,503 8,051
Amortization of debt financing costs........ 2,399 1,983 1,696
Impairment of oil and gas properties........ 103,490 -- --
Gain on sale of assets, net................. (882) (657) (85,294)
Loss on assets held for sale................ 3,494 -- --
Deferred income taxes....................... (54,804) 6,034 (6,476)
Debt modification costs..................... -- -- 3,064
Non-cash effect of discontinued operations.. 4,001 8,588 7,581
Other....................................... 6,912 (31) 1,030
--------- --------- ---------
73,577 92,362 34,082
Working capital changes, net of non-cash
transactions
Accounts receivable......................... 23,043 (26,266) (20,461)
Accounts payable............................ 9,876 5,403 (4,527)
Accrued liabilities......................... (7,880) 25,490 17,901
Other....................................... 2,468 (3,287) (2,971)
--------- --------- ---------
Net cash provided by operating
activities............................... 101,084 93,702 24,024
--------- --------- ---------
Cash flows from investing activities
Additions to oil and gas properties.......... (145,418) (104,420) (125,919)
Acquisitions of oil and gas properties....... (28,456) -- --
Proceeds from sales of properties............ 6,145 3,083 234,312
Additions to gas plant and other facilities.. (8,554) (3,388) (10,247)
--------- --------- ---------
Net cash provided by (used in) investing
activities............................... (176,283) (104,725) 98,146
--------- --------- ---------
Cash flows from financing activities
Proceeds from borrowings..................... 143,450 197,100 142,590
Debt issuance and modification costs......... (97) (5,186) (8,053)
Payments of long-term debt................... (102,100) (128,873) (223,392)
Proceeds from exercise of stock options...... 3,694 2,701 1,690
Purchase of treasury shares.................. (2,085) (25,560) (32,120)
--------- --------- ---------
Net cash provided by (used in) financing
activities............................... 42,862 40,182 (119,285)
--------- --------- ---------
Increase (decrease) in cash and cash
equivalents.................................. (32,337) 29,159 2,885
Cash and cash equivalents
Beginning of year............................ 39,447 10,288 7,403
--------- --------- ---------
End of year.................................. $ 7,110 $ 39,447 $ 10,288
========= ========= =========
See accompanying notes.
5
NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(In thousands)
Accumulated
Common Stock Additional Other Total
-------------- Paid-In Treasury Stock Held by Comprehensive Deferred Accumulated Stockholders'
Shares Amount Capital Stock Benefit Trust Income Compensation Deficit Equity
------ ---------------------- ----------------------------------------------------------
January 1,
1999........... 19,787 $203 $355,600 $(19,335) $(1,732) $ -- $ -- $(102,858) $231,878
====== ==== ======== ======== ======= ========== ===== ========= ========
Exercise of
stock options
and related tax
benefit........ 129 1 1,810 -- -- -- -- -- 1,811
Stock acquired
by benefit
trust.......... -- -- -- 1,850 (1,850) -- -- -- --
Issuance of
warrants and
other.......... -- -- 120 -- -- -- -- -- 120
Withdrawal from
benefit trust.. 14 -- -- -- 398 -- -- -- 398
Purchase of
Treasury
shares......... (1,999) -- -- (32,120) -- -- -- -- (32,120)
Deferred stock
compensation... -- -- 325 -- -- -- (216) -- 109
Net income...... -- -- -- -- -- -- -- 31,442 31,442
------ ---- -------- -------- ------- ---------- ----- --------- --------
December 31,
1999........... 17,931 204 357,855 (49,605) (3,184) (216) (71,416) 233,638
====== ==== ======== ======== ======= ========== ===== ========= ========
Exercise of
stock options
and related tax
benefit........ 183 2 3,200 -- -- -- -- -- 3,202
Stock acquired
by benefit
trust.......... -- -- -- 462 (462) -- -- -- --
Purchase of
Treasury
shares......... (1,482) -- -- (25,560) -- -- -- -- (25,560)
Deferred stock
compensation... -- -- 588 -- -- -- (386) -- 202
Net income...... -- -- -- -- -- -- -- 11,635 11,635
------ ---- -------- -------- ------- ---------- ----- --------- --------
December 31,
2000........... 16,632 206 361,643 (74,703) (3,646) (602) (59,781) 223,117
====== ==== ======== ======== ======= ========== ===== ========= ========
Exercise of
stock options
and related tax
benefit........ 287 3 4,463 -- -- -- -- -- 4,466
Stock acquired
by benefit
trust.......... -- -- -- 933 (933) -- -- -- --
Purchase of
Treasury
shares......... (128) -- -- (2,085) -- -- -- -- (2,085)
Deferred stock
compensation... -- -- 686 -- -- -- (300) -- 386
Withdrawal from
benefit trust
(Note 10)...... 89 -- -- -- 1,660 -- -- -- 1,660
Other
comprehensive
income......... -- -- -- -- -- 11,534 -- -- 11,534
Net loss........ -- -- -- -- -- -- -- (79,171) (79,171)
------ ---- -------- -------- ------- ---------- ----- --------- --------
December 31,
2001........... 16,880 $209 $366,792 $(75,855) $(2,919) $11,534 $(902) $(138,952) $159,907
====== ==== ======== ======== ======= ========== ===== ========= ========
See accompanying notes.
6
NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
AND CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME
(In thousands)
Year Ended December 31,
-------------------------
2001 2000 1999
-------- -------------
Comprehensive Income
Net income (loss).................................... $(79,171) $11,635 $31,442
Unrealized gains (losses) from cash flow hedging
activity:
Cumulative effect transition adjustment
(net of tax benefit of $10,784)................... (15,976) -- --
Reclassification adjustment of settled contracts
(net of taxes of $19,202)......................... 28,446 -- --
Changes in fair value of derivative instruments
during the period (net of tax benefit of $632).... (936) -- --
-------- -------------
Other comprehensive income........................ 11,534 -- --
-------- -------------
Comprehensive income................................. $(67,637) $11,635 $31,442
======== ======= =======
Accumulated Other Comprehensive Income
Beginning balances as of December 31, 2000, 1999 and
1998................................................ $ -- $ -- $ --
Unrealized gains (losses) from cash flow hedging
activity:
Cumulative effect transition adjustment, net of tax
benefit........................................... (15,976) -- --
Reclassification of initial cumulative effect
transition adjustment at original value, net of
taxes............................................. 20,917 -- --
Additional reclassification adjustments for changes
in initial value to settlement date, net of
taxes............................................. 7,529 -- --
Changes in fair value of derivative instruments
during the period, net of tax benefit............. (936) -- --
-------- -------------
Balance as of December 31,............................ $ 11,534 $ -- $ --
======== ======= =======
See accompanying notes.
7
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. Organization
Nuevo Energy Company ("Nuevo") was formed as a Delaware corporation on March
2, 1990, to acquire the businesses of certain public and private partnerships
(collectively "Predecessor Partnerships"). On July 9, 1990, the plan of
consolidation ("Plan of Consolidation") was approved by limited partners owning
a majority of units of limited partner interests in the partnerships whereby the
net assets of the Predecessor Partnerships, which were subject to the Plan of
Consolidation, were exchanged for Common Stock of Nuevo ("Common Stock"). All
references to "we", "us", "our" or the "Company" include Nuevo and its majority
and wholly-owned subsidiaries, unless otherwise indicated or the context
indicates otherwise.
We are engaged in the exploration for, and the acquisition, exploitation,
development and production of crude oil and natural gas. Our principal oil and
gas properties are located domestically onshore and offshore California and
the onshore Gulf Coast region, and internationally offshore the Republic of
Congo, West Africa.
2. Summary of Significant Accounting Policies
Principles of Consolidation
Our consolidated financial statements include the accounts of Nuevo and our
majority and wholly-owned subsidiaries. All significant intercompany accounts
and transactions have been eliminated in consolidation.
Oil and Gas Properties
We use the successful efforts method to account for our investments in oil
and gas properties. Under successful efforts, oil and gas lease acquisition
costs and intangible drilling costs associated with exploration efforts that
result in the discovery of proved reserves and costs associated with
development drilling, whether or not successful, are capitalized when
incurred. When a proved property is sold, ceases to produce or is abandoned, a
gain or loss is recognized. When an entire interest in an unproved property is
sold for cash or cash equivalent, a gain or loss is recognized, taking into
consideration any recorded impairment. When a partial interest in an unproved
property is sold, the amount received is treated as a reduction of the cost of
the interest retained.
Unproved leasehold costs are capitalized pending the results of exploration
efforts. Significant unproved leasehold costs are reviewed periodically and a
loss is recognized to the extent, if any, that the cost of the property has
been impaired. Exploration costs, including geological and geophysical
expenses, exploratory dry holes and delay rentals, are charged to expense as
incurred.
Costs of successful wells, development dry holes and proved leases are
capitalized and depleted on a unit-of-production basis over the remaining
proved reserves. Capitalized drilling costs are depleted on a unit-of-
production basis over the remaining proved developed reserves. Total estimated
costs of $113.1 million (net of salvage value) for future dismantlement,
abandonment and site remediation are included when calculating depreciation
and depletion using the unit-of-production method. At December 31, 2001, we
had recorded $74.2 million as a component of accumulated depreciation,
depletion and amortization related to this future obligation.
In accordance with Statement of Financial Accounting Standards ("SFAS") No.
121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed of, we review our long-lived assets to be held and used,
including proved oil and gas properties accounted for using the successful
efforts method of accounting, on a depletable unit basis whenever events or
circumstances indicate that the carrying value of those assets may not be
recoverable. SFAS No. 121 requires an impairment loss to be recognized when
the carrying amount of an asset exceeds the sum of the undiscounted estimated
future net cash flows and we recognize an impairment loss equal to the
difference between the carrying value and the fair value of the asset. Fair
value is estimated to be the present value of expected future net cash flows
from proved reserves, utilizing a risk-adjusted
8
rate of return. Also, in accordance with SFAS No. 121, when we classify an
asset as held for sale, if the carrying amount of the asset is less than their
fair market value less our estimated costs to sell the asset, the difference
is recognized as a loss in the period that we classify the asset as held for
sale.
During 2001, we recorded an impairment totaling $103.5 million on our Santa
Clara, Huntington Beach, Pitas Point, Masseko and Point Pedernales fields and
certain other oil and gas properties. We recorded no impairments in 2000 or
1999. (See Note 3.)
During 2001 and 1999, interest costs associated with non-producing leases
and exploration and development projects were capitalized only for the period
that activities were in progress to bring these projects to their intended
use. The capitalization rates were based on our weighted average cost of funds
used to finance expenditures. We capitalized $2.5 million and $0.3 million of
interest costs in 2001 and 1999. There were no interest costs capitalized in
2000.
Any reference to oil and gas reserve information in the Notes to the
Consolidated Financial Statements is unaudited.
Derivative Financial Instruments
We adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging
Activities, effective January 1, 2001. This statement requires all derivative
instruments to be carried on the balance sheet at fair value. In accordance
with the transition provisions of SFAS No. 133, we recorded a cumulative
effect transition adjustment of $(16.0) million, net of related tax benefit of
$10.8 million, in other comprehensive income to recognize the fair value of
our derivatives designated as cash-flow hedging instruments at the date of
adoption.
Beginning on January 1, 2001, all of our derivative instruments are
recognized on the balance sheet at their fair value. We currently use swaps
and put options to hedge our exposure to material changes in the future price
of crude oil and interest rate swaps to hedge the fair value of our long-term
debt.
On the date the derivative contract is entered into, we designate the
derivative as either a hedge of the fair value of a recognized asset,
liability or firm commitment ("fair value" hedge), as a hedge of the
variability of cash flows to be received ("cash-flow" hedge), or as a foreign
currency cash flow hedge. Changes in the fair value of a derivative that is
highly effective as, and that is designated and qualifies as, a fair-value
hedge, along with the change in fair value of the hedged asset or liability
that is attributable to the hedged risk (including losses or gains on firm
commitments), are recorded in current period earnings. Changes in the fair
value of a cash-flow hedge are recorded in other comprehensive income (loss)
until earnings are affected by the variability of cash flows. At December 31,
2001, we had both cash-flow hedges and fair value hedges. (See Note 16.)
We formally document all relationships between hedging instruments and
hedged items, as well as its risk-management objective and strategy for
undertaking various hedge transactions. This process includes linking all
derivatives that are designated as cash-flow hedges to forecasted
transactions. We also formally assess, both at the hedge's inception and on an
ongoing basis, whether the derivatives that are used in hedging transactions
are highly effective in offsetting changes in cash flows of hedged
transactions. When it is determined that a derivative is not highly effective
as a hedge or that it has ceased to be a highly effective hedge, we
discontinue hedge accounting prospectively.
When hedge accounting is discontinued because it is probable that a
forecasted transaction will not occur, the derivative will continue to be
carried on the balance sheet at its fair value, and gains and losses that were
accumulated in other comprehensive income will be recognized in earnings
immediately. In all other situations in which hedge accounting is
discontinued, the derivative will be carried at its fair value on the balance
sheet, with changes in its fair value recognized in earnings prospectively.
9
At December 31, 2001, we had recorded $11.5 million, net of related taxes
of $7.8 million, of cumulative hedging gains in other comprehensive income,
which will be reclassified to earnings within the next 12 months. The amounts
ultimately reclassified to earnings will vary due to changes in the fair value
of the open derivative contracts prior to settlement.
As a result of hedging transactions, oil and gas revenues were reduced by
$47.6 million, $117.7 million and $44.9 million in 2001, 2000 and 1999. The
portion of our hedging transactions that were ineffective totaled $0.2 million
in 2001 and was recorded as derivative gain on the Consolidated Income
Statement.
Price Risk Management Activities
We use price risk management activities to manage non-trading market risks.
We use derivative financial instruments such as swaps and put options to hedge
the impact market price risk exposures on our crude oil and natural gas
production.
Comprehensive Income
Comprehensive income includes net income and all changes in other
comprehensive income including changes in the fair value of derivatives
designated as cash-flow hedges.
Environmental Liabilities
Environmental expenditures that relate to current or future revenues are
expensed or capitalized as appropriate. Expenditures that relate to an
existing condition caused by past operations, and do not contribute to current
or future revenue generation, are expensed. Liabilities are recorded when
environmental assessments and/or clean-ups are probable, and the costs can be
reasonably estimated. Generally, the timing of these accruals coincides with
our commitment to a formal plan of action. As of December 31, 2001, we had
accrued approximately $5.1 million for future environmental expenditures.
Contingencies
We recognize liabilities for contingencies when we have an exposure that,
when fully analyzed, indicates it is both probable and that the amount can be
reasonably estimated. Funds spent to remedy these contingencies are charged
against a reserve, if one exists, or expensed. When a range of probable loss can
be estimated, we accrue the most likely amount.
Inventory
Our inventory is valued at the lower of cost or market. We had crude oil
inventory in Congo of $0.8 million and $3.2 million at December 31, 2001 and
2000. Our materials and supplies inventory totaled $3.0 million and $1.3
million at December 31, 2001 and 2000.
Gas Plant and Other Facilities
Gas plant and other facilities include the costs to acquire certain gas
plant and other facilities and to secure rights-of-way. Capitalized costs
associated with gas plant and other facilities are amortized primarily over
the estimated useful lives of the various components of the facilities
utilizing the straight-line method. The estimated useful lives of such assets
range from three to thirty years. We review these assets for impairment
whenever events or changes in circumstances indicate that their carrying
amounts may not be recoverable.
Recognition of Crude Oil and Natural Gas Revenue
Crude oil and natural gas revenue is recognized when title passes to the
purchaser. We use the entitlement method for recording sales of crude oil and
natural gas from producing wells. Under the entitlement method, revenue is
recorded based on our net revenue interest in production. Deliveries of crude
oil and natural gas in excess of our net revenue interests are recorded as
liabilities and under-deliveries are recorded as assets. Production imbalances
are recorded at the lower of the sales price in effect at the time of
production or the current market value. Substantially all such amounts are
anticipated to be settled with production in future periods. We did not have a
material imbalance position in terms of units or value at December 31, 2001 or
2000.
10
Stock-Based Compensation
We account for stock options under Accounting Principles Board Opinion
(APB) No. 25, Accounting for Stock Issued to Employees. No compensation
expense is recognized for such options. As allowed by SFAS No. 123, Accounting
for Stock-Based Compensation, we have continued to apply APB Opinion No. 25
for purposes of determining net income and to present the pro forma disclosure
required by SFAS No. 123.
Income Taxes
Deferred income taxes are accounted for under the asset and liability
method of accounting for income taxes. Under this method, deferred income
taxes are recognized for the tax consequences of temporary differences by
applying enacted statutory tax rates applicable to future years to differences
between the financial statement carrying amounts and the tax basis of existing
assets and liabilities. The effect on deferred taxes of a change in tax rates
is recognized in income in the period the change occurs.
Statements of Cash Flows
For cash flow presentation purposes, we consider all highly liquid money
market instruments with an original maturity of three months or less to be
cash equivalents. Interest paid in cash, net of amounts capitalized, for 2001,
2000 and 1999 was $38.3 million, $32.1 million and $33.5 million. Net amounts
paid (refunded) in cash for income taxes for 2001, 2000 and 1999 were $0.4
million, $(0.5) million and $2.3 million.
Change in Accounting Principle
Prior to December 31, 2000, we recorded inventory relating to quantities of
processed fuel oil and natural gas liquids in storage at current market
pricing. Also, fuel oil in inventory was stated at year end market prices less
transportation costs, and we recognized changes in the market value of
inventory from one period to the next as oil revenues. In December 2000, the
staff of the Securities and Exchange Commission announced that commodity
inventories should be carried at the lower of cost or market rather than at
market value. As a result, we changed our inventory valuation method to the
lower of cost or market in the fourth quarter of 2000, retroactive to the
beginning of the year and recorded a non-cash, cumulative effect of a change
in accounting principle to earnings, effective January 1, 2000, of $0.8
million, net of related income tax benefit of $0.5 million, to value product
inventory at the lower of cost or market. Quarterly results for 2000 were
restated to reflect this change in accounting.
Had we valued our product inventory at the lower of cost or market prior to
2000, net income would have been $30.6 million for the year ended December 31,
1999.
Use of Estimates
In order to prepare these financial statements in conformity with
accounting principles generally accepted in the United States, our management
has made a number of estimates and assumptions relating to the reporting of
assets and liabilities and the disclosure of contingent assets and
liabilities, as well as reserve information, which affects the depletion
calculation. Actual results could differ from those estimates.
Functional Currency
Our functional currency for all operations is the U.S. dollar.
New Accounting Pronouncements
Accounting for the Impairment or Disposal of Long-Lived Assets. In October
2001, the Financial Accounting Standards Board ("FASB") issued Statement of
Financial Accounting Standards ("SFAS") No. 144, Accounting for the Impairment
or Disposal of Long-Lived Assets. This Statement requires that long-lived assets
that are to be disposed of by sale be measured at the lower of book value or
fair value less cost to sell. The standard also expanded the scope of
discontinued operations to include all components of an entity with operations
that can be distinguished from the rest of the entity and that will be
eliminated from the ongoing operations of the entity in a disposal transaction.
We adopted the provisions of this statement effective January 1, 2002 and have
presented certain property dispositions as discontinued operations in accordance
with SFAS No. 144. (See Note 21).
Accounting for Goodwill and Other Intangible Assets. In June 2001, the FASB
issued SFAS No. 142, Goodwill and Other Intangible Assets. This statement
addresses the accounting for goodwill and other intangible assets after an
acquisition. It eliminates the requirement to amortize goodwill over its useful
life. Rather, goodwill will be subject to at least an annual assessment for
impairment by applying a fair-value based test. 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 Financial
Accounting Standards Board ("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.
11
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 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.
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.
Reclassifications
Certain reclassifications of prior period amounts have been made to conform
to the current presentation. The unaudited quarterly data footnote (Note 20)
also reflects reclassifications to conform with current presentation. These
reclassifications had no effect on net income or earnings per share.
3. Impairments
In accordance with SFAS No. 121, we review oil and gas properties for
impairment whenever events and circumstances indicate a decline in the
recoverability of their carrying value. If the expected undiscounted future
net cash flows of our oil and gas properties are lower than the carrying
amount of the oil and gas properties, the carrying amount is reduced to the
fair market value. Due to low commodity prices we undertook an impairment
review of our oil and gas properties. For some of our properties, the carrying
amount of the properties exceeded the estimated undiscounted future net cash
flows; thus, we adjusted the carrying amount of the respective oil and gas
properties to their fair value as determined by discounting their estimated
future net cash flows. The factors used to determine fair value included, but
were not limited to, estimates of proved reserves, future commodity prices,
timing of future production, future capital expenditures and a discount rate
commensurate with our internal rate of return on our oil and gas properties. As
a result, we recognized a non-cash pre-tax charge of $103.5 million ($62.0
million after tax) related to the impairment of oil and gas properties in the
fourth quarter of 2001. There were no impairments in 2000 or 1999.
4. Assets Held for Sale
In 2001, we made the decision not to pursue our power plant project in Kern
County, California due to the inability to secure the proper permits required.
We transferred our remaining equipment to assets held for sale and recognized
a $3.5 million loss in connection with writing down the equipment to their
estimated fair value less our costs to sell the assets of $0.8 million.
5. Acquisitions
In July 2001, we entered into a definitive agreement with Coho Anaguid,
Inc., Anadarko Tunisia Anaguid Company, and Pioneer Natural Resources Anaguid
Ltd., to acquire a portion of Coho's interest in the Anaguid Permit, a 1.1
million-acre permit located onshore southern Tunisia in the Ghadames Basin.
Our 10.42% working interest increased to 22.5%, subject to approval by the
Tunisian government. The Anaguid Permit, operated by Anadarko, is on trend
with the prolific Hassi Berkine and El Borma fields located to the west in
Algeria and Tunisia. Under the current work commitment, a well is expected to
be drilled in the Anaguid Permit during 2002.
In January 2001, we acquired approximately 2,900 acres of producing
properties previously held by Naftex ARM, LLC, in Kern County, California for
approximately $28.5 million. The newly acquired acreage is southeast of our
interest in the Cymric field, of which more than half is natural gas. In
addition, the acreage provides significant development potential.
In June 1999, we acquired working interests in oil and gas properties
located onshore and offshore California for $61.4 million from Texaco Inc. The
working interests in the acquired properties range from an additional 25%
interest in properties already owned and operated by us to 100%.
12
The acquisition included interests in Cymric, East Coalinga, Dos Cuadras, Buena
Vista Hills and other fields we operate.
6. Divestitures
In January 2002, we withdrew our request for formal government approval of
the Convention and Joint Venture resulting in a relinquishment of our interest
in the Alyane Permit located offshore Tunisia in the Gulf of Gabes.
As of June 17, 2001, we relinquished our 1.9 million-acre Accra-Keta Permit
offshore the Republic of Ghana. The Permit was relinquished prior to the
commencement of the second phase of the work program. We were the operator of
this Permit and held a 50% working interest. An impairment of $1.0 million was
recorded during the second and third quarters of 2001 in connection with this
relinquishment.
In May 2000, we sold our working interest in the Las Cienegas field in
California for approximately $4.6 million. We reclassified these assets to
assets held for sale during the third quarter of 1999, at which time we
discontinued depletion and depreciation. No impairment charge was recorded
upon reclassification to assets held for sale. In connection with this sale,
we unwound hedges of 2,800 BOPD for the period from May 2000 through December
2000 and recorded an adjusted net gain on sale of approximately $0.9 million.
We also sold certain non-core assets during 2000, recognizing a net loss of
approximately $0.3 million.
On December 31, 1999, we completed the sale of our working interests,
ranging from 8% to 100%, in 13 onshore fields and a gas processing plant
located in Ventura County, California, to Vintage Petroleum, Inc. The
effective date of the sale was September 1, 1999. We reclassified these
properties to assets held for sale and discontinued depleting and depreciating
these assets during the third quarter of 1999. Revenues less costs for the
period September 1, 1999, through December 31, 1999, and other adjustments
resulted in an adjusted sales price of $29.6 million at closing on December
31, 1999. Approximately $4.5 million of the proceeds was deposited in escrow
to address possible remediation issues. The funds will remain in escrow until
the Los Angeles Regional Water Quality Control Board approves completion of
the remediation work. All or any portion of the funds not used in remediation
shall be returned. As of December 31, 2001, the balance in the escrow account
remained at $4.5 million. The remainder of the proceeds from the sale were
used to repay a portion of our outstanding bank debt. We recorded a gain of
$5.3 million on the sale of these properties.
On January 6, 1999, we completed the sale of our East Texas natural gas
assets to an affiliate of Samson Resources Company for approximately $191.0
million. An escrow account of $100.0 million was funded with a portion of the
proceeds as discussed in Note 5. The remainder of the proceeds were used to
repay outstanding senior bank debt. We realized an $80.2 million adjusted pre-
tax gain on the sale of the East Texas natural gas assets resulting in the
realization of $14.6 million of our deferred tax asset. A $5.2 million gain on
settled hedge transactions was realized in connection with the closing of this
sale in 1999.
7. Outsourcing Services
Torch Energy Advisors Incorporated ("Torch"), through its affiliates is an
outside service provider primarily in the business of providing management and
advisory services relating to oil and gas assets.
Effective March 16, 2002, we will have the following outsourcing contracts
in force:
. oil and gas administration: we pay a monthly base fee which is adjusted
upward or downward to reflect the current number and type of properties
for which services are provided
. crude oil marketing: we pay a base charge and a variable charge based on
the volume of crude oil sold or marketed
13
Since 1999 Torch has provided the following services: oil and gas
administration (accounting, information technology and land administration),
human resources, corporate administration (legal, graphics, support, and
corporate insurance), crude oil marketing, natural gas marketing, land leasing
and field operations.
We have a Master Services Agreement with Torch, which contains the overall
terms and conditions governing each individual service agreement. The crude
oil marketing contract has one year remaining on its term while the oil and
gas administration agreement runs through 2003, with a possible one-year
extension. In late 2001, we terminated the California field operations and
human resources contracts and did not renew the gas marketing contract. The
termination required ninety days notice and is effective March 15, 2002. We
have reduced both the staffing requirements and cost structure under the Torch
agreements and brought certain professional and other positions in-house.
Under the Master Services Agreement, we paid outsourcing fees to Torch in
the amount of $8.4 million, $13.7 million and $14.1 million in 2001, 2000 and
1999. Torch operated certain oil and gas interests that we own. Since 1999 we
were charged, on the same basis as other third parties, for all customary
expenses and cost reimbursements associated with these activities. Fees
charged for field operations for the years ended December 31, 2001, 2000 and
1999, were $22.3 million, $21.8 million and $25.1 million. All fees paid to
Torch are reflected in operating costs. Upon the effective date of the
termination of these outsourcing agreements, we assume direct responsibility for
the California field operations.
A subsidiary of Torch marketed oil, natural gas and natural gas liquids
from certain of our oil and gas properties and gas plants. In 2001, 2000 and
1999, the marketing fees were $1.9 million, $1.8 million and $1.2 million.
Beginning in 2002, our natural gas is being marketed by a new provider, Coral
Energy.
8. Restructuring and Severance Charges
Termination of Outsourcing Agreements.
We terminated two outsourcing agreements with the objective of exercising
greater control over certain operating functions and lowering our costs. The
terminated agreements were the California field operations and human resources
effective March 15, 2002. We have retained a majority of the field employees
currently working on our California properties while the human resources
function was brought in-house. (See Note 7.)
Reorganization of Exploration and Production Operations.
We have reorganized our exploration and production operations in an effort
to reflect a smaller, more focused exploitation program and eliminated our
California exploration program. In connection with this reorganization,
approximately 20 technical positions were eliminated.
The following table details the amounts related to our restructuring and
severance:
Liability at
2001 Payments December 31,
Charges in 2001 2001
---------------------------------
(In thousands)
Severance, benefits and other.......... $2,178 $ 503 $1,675
Contract termination................... 2,681 -- 2,681
------ ------ ------
$4,859 $ 503 $4,356
====== ====== ======
14
9. Accounts Receivable
Our accounts receivable consisted of the following at December 31:
2001 2000
-------------
(In thousands)
Oil and gas sales........................................... $32,220 $61,018
Joint interest billings..................................... 9,348 7,754
Other....................................................... 6,736 3,005
-------------
$48,304 $71,777
======= =======
10. Stockholders' Equity
Common and Preferred Stock
Our Certificate of Incorporation authorizes the issuance of up to 50
million shares of Common Stock and 10 million shares of Preferred Stock, the
terms, preferences, rights and restrictions of which are established by our
Board of Directors. All shares of Common Stock have equal voting rights of one
vote per share on all matters to be voted upon by stockholders. Cumulative
voting for the election of directors is not permitted. Certain restrictions
contained in our loan agreements limit the amount of dividends that may be
declared. Under the terms of the most restrictive covenant in our indenture
for the 9 1/2% Senior Subordinated Notes due 2008 described in Note 12, we and
our restricted subsidiaries had $17.7 million available for the payment of
dividends and share repurchases at December 31, 2001. We have not paid
dividends on our Common Stock and do not anticipate the payment of cash
dividends in the immediate future.
EPS Computation
SFAS No. 128, Earnings per Share, requires a reconciliation of the
numerator (income) and denominator (shares) of the basic EPS computation to
the numerator and denominator of the diluted EPS computation. In 2001 and
1999, weighted average shares held by the benefit trust of 145,000 and 64,000
are not included in the calculation of diluted loss per share due to their
anti-dilutive effect. In 2001, stock options were excluded from the
calculation of diluted loss per share due to their anti-dilutive effect. In
2000 and 1999, we had 2.4 million and 2.5 million stock options which were not
included in the calculation of diluted earnings per share because the option
exercise price exceeded the average market price. We also have 2.3 million
Term Convertible Securities, Series A ("TECONS") that were not included in the
calculation of diluted earnings (loss) per share in 2001, 2000 or 1999 due to
their anti-dilutive effect. The reconciliation is as follows:
For the Year Ended December 31,
-----------------------------------------------
2001 2000 1999
-----------------------------------------------
Common Common Common
Shares Shares Shares
------ ------ ------
(In thousands)
Income (loss) from Continuing
Operations --Basic........... $(81,931) 16,735 $8,389 17,447 $31,766 19,353
Effect of dilutive securities:
Stock options............... -- -- -- 335 -- 154
Shares held by Benefit
Trust...................... -- -- (152) 159 -- --
-------- ------ ------ ------ ------- ------
Income (loss) from Continuing
Operations--Diluted.......... $(81,931) 16,735 $8,237 17,941 $31,766 19,507
======== ====== ====== ====== ======= ======
Treasury Stock Repurchases
On February 12, 2001, our Board of Directors authorized the open market
repurchase of an additional 1.0 million shares of common stock increasing the
amount authorized to repurchase to 5.6 million shares, of which
15
2.0 million is remaining. Repurchases may be made at times and at prices
deemed appropriate by management and consistent with the authorization of our
Board. During the first quarter of 2001, we repurchased 0.1 million shares at
an average purchase price of $16.32 per share, including commissions. There
were no shares repurchased during the second, third or fourth quarters of
2001. As of December 31, 2001, we had repurchased a total of 3.6 million
shares since December 1997, at an average purchase price of $16.56 per share,
including commissions.
Shareholder Rights Plan
In March 1997, we adopted a Shareholder Rights Plan to protect our
shareholders from coercive or unfair takeover tactics. Under the Shareholder
Rights Plan, each outstanding share and each share of subsequently issued
common stock has attached to it one Right. Generally, in the event a person or
group ("Acquiring Person") acquires or announces an intention to acquire
beneficial ownership of 15% or more of the outstanding shares of common stock
without our prior consent, or we are acquired in a merger or other business
combination, or 50% or more of our assets or earning power is sold, each
holder of a Right will have the right to receive, upon exercise of the Right,
that number of shares of common stock of the acquiring company, which at the
time of such transaction will have a market price of two times the exercise
price of the Right. We may redeem the Right for $.01 at any time before a
person or group becomes an Acquiring Person without prior approval. The Rights
will expire on March 21, 2007, subject to earlier redemption by us.
On January 10, 2000, we amended the Shareholder Rights Plan to provide that
if we receive and consummate a transaction pursuant to a qualifying offer, the
provisions of the Shareholder Rights Plan are not triggered. In general, a
qualifying offer is an all cash, fully-funded tender offer for all outstanding
common shares by a person who, at the commencement of the offer, beneficially
owns less than five percent of the outstanding common shares. A qualifying
offer must remain open for at least 120 days, must be conditioned on the
person commencing the qualifying offer acquiring at least 75% of the
outstanding common shares and the per share consideration must exceed the
greater of (1) 135% of the highest closing price of the common shares during
the one-year period prior to the commencement of the qualifying offer or (2)
150% of the average closing price of the common shares during the 20 day
period prior to the commencement of the qualifying offer.
Executive Compensation Plan
In 1997, we adopted a plan to encourage senior executives to personally
invest in our stock, and to regularly review executives' ownership versus
targeted ownership objectives. These incentives include a deferred
compensation plan (the "Plan") that gives key executives the ability to defer
all or a portion of their salaries and bonuses and invest in our common stock
or make other investments at the employee's discretion. Stock is held in a
benefit trust and is restricted for a two-year period. The stock held in the
benefit trust (122,995 shares, 174,904 shares and 75,904 shares at December
31, 2001, 2000 and 1999) is accounted for as a liability at market value, with
any changes in market value charged or credited to general and administrative
expense. We recorded a net benefit of $0.2 million and $0.1 million in 2001
and 2000 and an expense of $1.7 million in 1999 related to deferred
compensation. The Plan was amended in 2001 to remove the discount on
investments in our common stock and to provide additional investment
alternatives. Target levels of ownership are based on multiples of base salary
and are administered by the Compensation Committee of the Board of Directors.
Upon withdrawal from the Plan, the obligation to the employee can be settled
in cash or Common Stock, at the option of the employee. In 2001 and 1999,
89,000 shares and 14,000 shares were withdrawn from the Plan at a fair market
value of $1.7 million and $0.4 million. In 2000, there were no such
withdrawals from the Plan. The Plan applies to certain highly compensated
employees and all executives at a level of Vice-President and above.
Director Compensation
In May 1999, the Compensation Committee of our Board of Directors
implemented changes to the compensation of our non-employee directors. Non-
employee directors may elect to receive all or part of the annual cash
retainer of $30,000 in restricted shares of our Common Stock at a 33% increase
in value. The election must be made in increments of 25% ($7,500). Therefore,
for each $7,500 of compensation for which the
16
election is exercised, the director would receive $9,975 in restricted stock.
Each non-employee director also receives a semi-annual grant of 1,750 ten-year
options to purchase our Common Stock at the market price of the stock on the
date of the grant. Non-employee directors also receive a semi-annual grant of
1,250 restricted shares of our common stock. All restricted shares are subject
to a three-year restricted period. Directors have the option of deferring
delivery of restricted shares beyond the three-year period.
Stock Incentive Plans
In 1990, we established the 1990 Stock Option Plan; in 1993, the Board of
Directors adopted the Nuevo Energy Company 1993 Stock Incentive Plan; and in
1999, the Board of Directors adopted the Nuevo Energy Company 1999 Stock
Incentive Plan (collectively, the "Stock Incentive Plans"). In 2001, the Board
of Directors adopted the 2001 Stock Incentive Plan as well as individual
incentive plans to induce our Chief Financial Officer and our Senior Vice
President to accept employment with us. In 2001, we recorded $0.1 million of
general and administration expense related to 9,073 shares of common stock
granted to our Chief Executive Officer in accordance with his employment
agreement. The purpose of the Stock Incentive Plans is to provide our
directors and key employees performance incentives and to provide a means of
encouraging these individuals to own our stock.
The total maximum number of shares subject to options under the Stock
Incentive Plans is 5,000,000 shares. Options are granted under the Stock
Incentive Plans on the basis of the optionee's contribution to us. No option
may exceed a term of more than ten years. Options granted under the Stock
Incentive Plans may be either incentive stock options or options that do not
qualify as incentive stock options. Our Compensation Committee is authorized
to designate the recipients of options, the dates of grants, the number of
shares subject to options, the option price, the terms of payment upon
exercise of the options, and the time during which the options may be
exercised. Options for officers vest over a term of one to three years, as
specified by the Compensation Committee. Officers who have met their targeted
stock ownership requirement receive accelerated vesting on all options issued
prior to October 15, 2001.
The following table details a summary of activity in the stock option plans
during the three years ended 2001:
Weighted-
Average
Option Exercise Price
--------- --------------
Outstanding at January 1, 1999.................... 2,676,363 $23.94
Granted......................................... 481,225 $16.02
Exercised....................................... (128,909) $14.16
Canceled........................................ (411,500) $25.52
---------
Outstanding at December 31, 1999.................. 2,617,179 $22.72
Granted......................................... 419,189 $15.69
Exercised....................................... (182,925) $13.40
Canceled........................................ (80,525) $34.18
---------
Outstanding at December 31, 2000.................. 2,772,918 $21.94
Granted......................................... 875,026 $15.51
Exercised....................................... (287,000) $12.93
Canceled........................................ (102,525) $33.88
---------
Outstanding at December 31, 2001.................. 3,258,419 $20.62
=========
17
We had options exercisable of 2,728,494 (weighted average exercise price of
$21.80), 2,361,979 (weighted average exercise price of $23.04) and 2,202,454
(weighted average exercise price of $24.00) at December 31, 2001, 2000 and
1999. Detail of stock options outstanding and options exercisable at December
31, 2001 follows:
Outstanding Exercisable
--------------------------------------------------
Weighted- Weighted- Weighted-
Average Average Average
Remaining Exercise Exercise
Range of Exercise Prices Number Life (Years) Price Number Price
------------------------ --------------------------------------------
$10.31 to $15.06........ 854,263 8.27 $12.36 576,763 $12.51
$15.50 to $19.63........ 1,453,956 7.28 $16.89 1,202,031 $16.81
$20.38 to $29.88........ 407,700 5.14 $23.27 407,200 $23.27
$34.00 to $47.88........ 542,500 5.69 $41.62 542,500 $41.62
--------- ---------
Total................. 3,258,419 2,728,494
========= =========
The weighted-average fair value of options granted during 2001, 2000 and
1999 was $10.63, $10.87 and $11.38. The fair value of each option grant is
estimated on the date of grant using the Black-Scholes option-pricing model
with the following weighted-average assumptions: expected stock price
volatility of 54.5%, 112% and 55.7% in 2001, 2000 and 1999; risk free interest
of 4%, 5% and 6% in 2001, 2000 and 1999, and average expected option lives of
three years in 2001 and 2000 and five years in 1999. Had compensation expense
for stock-based compensation been determined based on the fair value at the
date of grant, our net income, earnings available to common stockholders and
earnings per share would have been reduced to the pro forma amounts indicated
below.
Year Ended December 31,
-------------------------
2001 2000 1999
-------- -------------
(In thousands, except
share data)
Net income (loss).................... As reported $(79,171) $11,635 $31,442
Pro forma (83,177) 6,740 24,673
Earnings (loss) per Common share--
Basic............................... As reported (4.73) 0.67 1.62
Pro forma (4.97) 0.39 1.27
Earnings (loss) per Common share--
Diluted............................. As reported (4.73) 0.64 1.61
Pro forma (4.97) 0.38 1.26
11. Company-Obligated Mandatorily Redeemable Convertible Preferred Securities
of Nuevo Financing I
On December 23, 1996, the Company and Nuevo Financing I, a statutory
business trust formed under the laws of the state of Delaware, (the "Trust"),
closed the offering of 2.3 million TECONS on behalf of the Trust. The price to
the public was $50.00 per TECONS. Distributions began to accumulate from
December 23, 1996, and are payable quarterly on March 15, June 15, September
15, and December 15, at an annual rate of $2.875 per TECONS. Each TECONS is
convertible at any time prior to the close of business on December 15, 2026,
at the option of the holder into shares of common stock at the rate of 0.8421
shares of common stock for each TECONS, subject to adjustment. The sole asset
of the Trust as the obligor on the TECONS is $115.0 million aggregate
principal amount of 5.75% Convertible Subordinated Debentures ("Debentures")
of the Company due December 15, 2026. The Debentures were issued by us to the
Trust to facilitate the offering of the TECONS. The TECONS must be redeemed
for $50.00 per TECON plus accrued and unpaid dividends on December 15, 2026.
18
12. Long-Term Debt
Our long-term debt consisted of the following at December 31:
2001 2000
-------- --------
(In thousands)
9 3/8% Senior Subordinated Notes due 2010................ $150,000 $150,000
9 1/2% Senior Subordinated Notes due 2008................ 257,210 257,310
9 1/2% Senior Subordinated Notes due 2006................ 2,367 2,417
Bank credit facility (at 3.71% on December 31, 2001)..... 41,500 --
-------- --------
Total debt............................................. 451,077 409,727
Interest rate swaps...................................... (633) --
-------- --------
Long-term debt........................................... $450,444 $409,727
======== ========
9 3/8% Notes due 2010
On September 26, 2000, we issued $150.0 million of 9 3/8% Senior
Subordinated Notes due October 1, 2010. Interest accrues at 9 3/8% per annum
and is payable semi-annually in arrears on April 1 and October 1. The Notes
are redeemable, in whole or in part, at our option, on or after October 1,
2005, under certain conditions. We are not required to make mandatory
redemption or sinking fund payments with respect to these Notes. The indenture
contains covenants that, among other things, limit our ability to incur
additional indebtedness, limit restricted payments, limit issuances and sales
of capital stock by restricted subsidiaries, limit dispositions of proceeds
from asset sales, limit dividends and other payment restrictions affecting
restricted subsidiaries, and restrict mergers, consolidations or sales of
assets. If one of our subsidiaries guarantees other subordinated indebtedness
of ours, the subsidiary must also guarantee these Notes. Currently, none of
our subsidiaries guarantee subordinated indebtedness of ours. The Notes are
unsecured general obligations, and are subordinated in right of payment to all
existing and future senior indebtedness. In the event of a defined change in
control, we will be required to make an offer to repurchase all outstanding 9
3/8% Notes at 101% of the principal amount, plus accrued and unpaid interest
to the date of redemption.
9 1/2% Notes due 2008
In July 1999, we authorized a new issuance of $260.0 million of 9 1/2%
Senior Subordinated Notes due June 1, 2008. In August 1999, we exchanged these
Notes for $157.5 million of our 9 1/2% Notes due 2006 and $99.9 million of our
8 7/8% Senior Subordinated Notes due 2008. In connection with the exchange
offers, we solicited consents to proposed amendments to the indentures under
which the exchanged notes were issued. These amendments streamlined our
covenant structure and provided us with additional flexibility to pursue our
operating strategy. The exchange was accounted for as a debt modification and
the consideration we paid to the holders of the exchanged 9 1/2% Notes due
2006 was $4.7 million and was accounted for as deferred financing costs. We
also incurred a total of $3.1 million in third-party fees during the third and
fourth quarters of 1999, which are included in other expense.
Interest on these Notes accrues at the rate of 9 1/2% per annum and is
payable semi-annually in arrears on June 1 and December 1. These Notes are
redeemable, in whole or in part, at our option, on or after June 1, 2003,
under certain conditions. We are not required to make mandatory redemption or
sinking fund payments on these Notes. The indenture contains covenants that,
among other things, limit the Company's ability to incur additional
indebtedness, limit restricted payments, limit issuances and sales of capital
stock by restricted subsidiaries, limit dispositions of proceeds from asset
sales, limit dividends and other payment restrictions affecting restricted
subsidiaries, and restrict mergers, consolidations or sales of assets. The 9
1/2% Notes are not currently guaranteed by our subsidiaries but are required
to be guaranteed by any subsidiary that guarantees pari passu or subordinated
indebtedness. Currently, none of our subsidiaries guarantees our subordinated
indebtedness. The 9 1/2% Notes are unsecured general obligations, and are
subordinated in right of payment to all of our existing and future senior
indebtedness. In the event of a defined change in control, we will be required
to make an offer to repurchase all outstanding Notes at 101% of the principal
amount, plus accrued and unpaid interest to the date of redemption.
19
9 1/2% Notes due 2006
In April 1996, we issued $160.0 million of 9 1/2% Notes due 2006 and used
the proceeds to pay for a portion of the purchase price of the Unocal
Properties. In August 1999, we exchanged $157.5 million of these notes for our
9 1/2% Notes due 2008. In October 1999, we purchased $0.1 million of the
remaining Notes. No significant costs were incurred in connection with that
early retirement. Interest on these Notes accrues at the rate of 9 1/2% per
annum and is payable semi-annually in arrears on April 15 and October 15 and
were redeemable, in whole or in part, at our option, on or after April 15,
2001, under certain conditions. These Notes had not been redeemed, in whole,
or in part at December 31, 2001. We are not required to make mandatory
redemption or sinking fund payments with respect to these Notes and they are
unsecured general obligations, and are subordinated in right of payment to all
existing and future senior indebtedness.
Interest Rate Swaps
In December 2001, we entered into two interest rate swap agreements with
notional amounts totaling $150 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 $0.6
million as of December 31, 2001 with a corresponding increase in 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 $100 million, and we pay the counterparty a variable
annual rate equal to the six-month London Interbank Offered Rate ("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%.
Subsequent to December 31, 2001, we entered into an interest rate swap
agreement with a notional amount totaling $50 million to hedge the fair value
of our 9 3/8% Notes. Under the terms of this agreement, the counterparty pays
us a weighted average fixed annual rate of 9 3/8% on the notional amount of
$50 million, and we pay the counterparty a variable annual rate equal to the
three-month LIBOR rate plus a weighted average rate of 3.49%
Bank Credit Facility
Our Third Amended and Restated Credit Agreement ("Credit Agreement"), dated
June 7, 2000, provides for secured revolving credit availability of up to
$410.0 million from a bank group led by Bank of America, N.A., Bank One, NA,
and Bank of Montreal until its expiration on June 7, 2005.
The borrowing base is subject to a semi-annual borrowing base determination
within 60 days following March 1 and August 15 of each year and establishes
the maximum borrowings that may be outstanding under the credit facility. It
is determined by a 60% vote of the banks (two-thirds in the event of an
increase in the borrowing base), each of which bases its judgement on: (i) the
present value of our oil and gas reserves based on their own assumptions
regarding future prices, production, costs, risk factors and discount rates,
and (ii) projected cash flow coverage ratios calculated under varying
scenarios. If amounts outstanding under the credit facility exceed the
borrowing base, as redetermined from time to time, we would be required to
repay such excess over a defined period of time. We have a $225 million
borrowing base under our Credit Facility with $102 million available at
December 31, 2001 and had drawn $41.5 million under the agreement.
Amounts outstanding under the credit facility bear interest at a rate equal
to LIBOR plus an amount which increases as the Indebtedness (as defined in the
Credit Agreement) increases.
Our Credit Agreement has covenants which limit certain restricted payments
and investments, guarantees and indebtedness, prepayments of subordinated and
certain other indebtedness, mergers and consolidations, certain types of
acquisitions and on the issuance of certain securities by subsidiaries, liens,
sales of properties,
20
transactions with affiliates, derivative contracts and debt in subsidiaries.
We are also required to maintain certain financial ratios and conditions,
including without limitation an EBITDAX (earnings before interest, taxes,
depreciation, depletion, amortization and exploration expenses) to fixed
charge coverage ratio and a funded debt to capitalization ratio. At December
31, 2001, we were in compliance with all covenants of the Credit Agreement.
The amount of scheduled debt maturities during the next five years and
thereafter is as follows (amounts in thousands):
2002................................................................ $ --
2003................................................................ --
2004................................................................ --
2005................................................................ 41,500
2006................................................................ 2,367
Thereafter.......................................................... 407,210
--------
Total debt maturities............................................. $451,077
========
Based upon the quoted market price, the fair value of the 9 3/8% Notes was
estimated to be $146.5 million and 150.0 million at December 31, 2001 and
2000; the fair value of the 9 1/2% Notes due 2008 was estimated to be $245.6
million and $260.4 million at December 31, 2001 and 2000, and the fair value
of the 9 1/2% Notes due 2006 was estimated to be $2.4 million and $2.5 million
at December 31, 2001 and 2000. The carrying amount of the credit facility
approximates the fair value of the debt at December 31, 2001.
13. Income Taxes
Income tax (expense) benefit is summarized as follows:
Year Ended December 31,
-------------------------
2001 2000 1999
------- ------- -------
(In thousands)
Current
Federal......................................... $ -- $ 371 $(1,012)
State........................................... -- -- (188)
------- ------- -------
-- 371 (1,200)
------- ------- -------
Deferred
Federal......................................... 43,946 (4,913) 8,326
State........................................... 10,858 (1,121) (1,931)
------- ------- -------
54,804 (6,034) 6,395
------- ------- -------
Total income tax (expense) benefit............ $54,804 $(5,663) $ 5,195
======= ======= =======
For the year ended December 31, 2000, we recorded a tax benefit of $0.5
million related to the cumulative effect of a change in accounting principle
(see Note 2). For the years ended December 31, 2001, 2000 and 1999, we recorded
a tax benefit (expense) of ($1.8 million), ($2.7 million), and $0.2 million,
respectively, related to income (loss) from discontinued operations, including
loss on disposition. A deferred tax benefit related to the exercise of employee
stock options of approximately $0.8 million and $0.5 million was allocated
directly to additional paid-in capital in 2001 and 2000.
21
Total income tax expense (benefit) differs from the amount computed by
applying the federal income tax rate to income (loss) from continuing
operations. The reasons for these differences are as follows:
Year Ended
December 31,
--------------------
2001 2000 1999
----- ----- -----
Statutory federal income tax rate..................... (35.0)% 35.0% 35.0%
(Decrease) increase in tax rate resulting from:
State income taxes, net of federal benefit.......... (5.2) 5.2 5.2
Decrease in valuation allowance..................... -- -- (60.8)
Nondeductible travel and entertainment and other.... 0.1 0.1 0.1
----- ----- -----
(40.1)% 40.3 % (20.5)%
===== ===== =====
During 1999, we determined that it would be more likely than not that the
deferred tax assets would be realized. At such time, we reduced the valuation
allowance by $15.9 million.
The tax effects of temporary differences that result in significant
portions of the deferred income tax assets and liabilities and a description
of the financial statement items creating these differences are as follows:
As of December
31,
-----------------
2001 2000
------- --------
(In thousands)
Net operating loss carryforwards.......................... $57,568 $ 51,033
Alternative minimum tax credit carryforwards.............. 1,704 1,704
Property and equipment.................................... 3,261 --
State income taxes........................................ 5,268 --
------- --------
Total deferred income tax assets........................ 67,801 52,737
Less: valuation allowance............................... (1,777) (1,777)
------- --------
Net deferred income tax assets.......................... 66,024 50,960
------- --------
Property and equipment.................................... -- (31,338)
Equity in foreign subsidiaries............................ (1,854) (1,684)
State income taxes........................................ (1,940) (1,656)
------- --------
Total deferred income tax liabilities................... (3,794) (34,678)
------- --------
Net deferred income tax asset(1).......................... $62,230 $ 16,282
======= ========
- ------------
(1) The 2001 amount includes $7,783 related to derivatives in other
comprehensive income.
At December 31, 2001, we had a net operating loss carryforward for regular
tax purposes of approximately $164.5 million, which will begin expiring in
2018. Alternative minimum tax credit carryforwards of $1.7 million does not
expire and may be applied to reduce regular income tax to an amount not less
than the alternative minimum tax payable in any one year. At December 31,
2001, we determined that it was more likely than not that most of the deferred
tax assets would be realized.
22
14. Industry Segment Information
Our operations are concentrated primarily in two segments: exploration and
production of oil and natural gas, and gas plant and other facilities. 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:
As of and For the Year
Ended
December 31,
-----------------------------
2001 2000 1999
--------- -------- --------
(In thousands)
Sales to unaffiliated customers
Oil and gas--Domestic......................... $ 309,019 $265,917 $195,032
Oil and gas--Foreign.......................... 36,020 40,944 30,664
--------- -------- --------
Total sales................................. 345,039 306,861 225,696
Other income.............................. 273 2,358 4,778
--------- -------- --------
Total revenues.............................. $ 345,312 $309,219 $230,474
========= ======== ========
Income (loss) from continuing operations before
income taxes
Oil and gas--Domestic......................... $ (22,110) $ 77,928 $ 98,318
Oil and gas--Foreign.......................... (8,351) 14,947 5,245
--------- -------- --------
(30,461) 92,875 103,563
Unallocated corporate expenses................ 56,655 34,738 37,350
Interest expense.............................. 43,006 37,472 33,110
Dividends on TECONS........................... 6,613 6,613 6,613
--------- -------- --------
Income (loss) from continuing operations
before income taxes.......................... $(136,735) $ 14,052 $ 26,490
========= ======== ========
Identifiable assets
Oil and gas--Domestic......................... $ 541,688 $613,658 $566,256
Oil and gas--Foreign.......................... 56,404 103,204 82,074
Gas plant and other facilities................ 7,395 11,455 12,297
--------- -------- --------
605,487 728,317 660,627
Corporate assets, investments and other....... 234,325 119,707 99,403
--------- -------- --------
Total....................................... $ 839,812 $848,024 $760,030
========= ======== ========
Capital expenditures (/2/)
Oil and gas--Domestic......................... $ 163,991 $101,773 $106,071
Oil and gas--Foreign.......................... 24,972 11,694 24,570
--------- -------- --------
Total oil and gas expenditures.............. 188,963 113,467 130,641
Less: Geological & geophysical, delay rentals
and other expenses........................... (15,089) (9,047) (4,722)
--------- -------- --------
Additions to oil and gas properties per
Statement of Cash Flows.................... $ 173,874 $104,420 $125,919
========= ======== ========
Gas plant and other facilities................ $ 8,554 $ 3,388 $ 10,247
========= ======== ========
Depreciation, depletion and amortization
Oil and gas--Domestic......................... $ 61,331 $ 51,960 $ 62,360
Oil and gas--Foreign.......................... 10,381 8,085 9,177
Gas plant and other facilities................ 512 512 666
Corporate..................................... 1,776 954 785
--------- -------- --------
Total....................................... $ 74,000 $ 61,511 $ 72,988
========= ======== ========
- --------
(/1/Includes)gain on sale of the East Texas natural gas asset of $80.2 million
in 1999.
(/2/Includes)acquisitions of oil and gas properties.
23
Credit Risks due to Certain Concentrations
In 2001, 2000 and 1999, we had one customer that accounted for 63%, 84%,
and 79% of oil and gas revenues. In 2001, 2000 and 1999, we had another
customer that accounted for 23%, 11% and 12% of oil and gas revenues.
In February 2000, we entered into a 15-year contract, effective January 1,
2000, to sell substantially all of our current and future California crude oil
production to Tosco Corporation. The contract provides pricing based on a
fixed percentage of the NYMEX crude oil price for each type of crude oil that
we produce in California. Therefore, the actual price received as a percentage
of NYMEX will vary with our production mix. Based on the current production
mix, the price we receive for our California production is expected to average
approximately 72% of West Texas Intermediate ("WTI"). While the contract does
not reduce our exposure to price volatility, it does effectively eliminate the
basis differential risk between the NYMEX price and the field price of our
California oil production. The Tosco contract permits us, under certain
circumstances, to separately market up to ten percent of our California crude
production. We exercised this right and, effective January 1, 2001, and
January 1, 2002, began selling 5,000 BOPD of our San Joaquin Valley oil
production to a third party under a one-year contract using NYMEX pricing.
Our revenues are derived principally from uncollateralized sales to
customers in the oil and gas industry, therefore, customers may be similarly
affected by changes in economic and other conditions within the industry. We
have not experienced significant credit losses in such sales. Sales of oil and
gas to Tosco are similarly uncollateralized.
15. 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. Production was back on in January 2002. In 2002, we
reached a final agreement with our underwriters with respect to our business
interruption claim. Certain costs related to repair and business interruption
are expected to be covered by insurance based in a tentative agreement we have
with our underwriters.
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 and the
cause of the failure is under investigation. Crude oil and natural gas
produced from three fields offshore California are transported onshore by
pipeline to the ROSF plant where crude oil and water are separated and
treated, and carbon dioxide is removed from the natural gas stream. The daily
net production associated with these fields is 3,000 barrels of crude oil and
2.4 MMcf of 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.
24
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 litigation. 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 March 1999, we discovered that a non-officer employee had fraudulently
authorized and diverted for personal use Company funds totaling $5.9 million,
$1.6 million in 1999 and the remainder in 1998, that were intended for
international exploration. The Board of Directors engaged a Certified Fraud
Examiner to conduct an in-depth review of the fraudulent transactions. The
investigation confirmed that only one employee was involved in the matter and
that all misappropriated funds were identified. We have reviewed and, where
appropriate, strengthened our internal control procedures. In August 2000, we
recorded $1.5 million of other income for a partial reimbursement of these
previously expensed funds, resulting from the negotiated settlement of a
related legal claim.
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 $120,000. We incurred clean-up and repair costs of $0.3
million, $ 0.3 million and $0.5 million during 2001, 2000 and 1999. As of
December 31, 2001, we had received insurance reimbursements of $4.2 million,
with a remaining insurance receivable of $0.5 million. For amounts not covered
by insurance, including the $0.1 million deductible, we recorded lease
operating expenses of $1.1 million in 2001 and $0.4 million during 1999. No
such expenses were recorded in 2000. 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
25
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 US
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.
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.
At December 31, 2001, we had capital commitments of $2.6 million primarily
relating to our international oil and gas exploration and development activity.
Our other planned capital projects are discretionary in nature, with no
substantial capital commitments made in advance of the actual expenditures.
The minimum annual rental commitments for the next five years and thereafter
are $1.5 million in 2002, $1.5 million in 2003, $1.6 million in 2004, $1.6
million in 2005, $1.4 million in 2006 and $2.4 million thereafter.
16. 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 these hedges are based on West Texas
Intermediate ("WTI") barrels. Our production is expected to average 73% of
WTI, therefore, each WTI barrel hedges 1.37 barrels of our production.
Derivative Instruments Designated as Cash Flow Hedges
At December 31, 2001, we had entered into the following cash flow hedges:
WTI Barrels Average
Per Day Strike Price
----------------------
Swaps
First quarter 2002................................ 12,500 $25.91
Second quarter 2002............................... 2,000 23.50
Third quarter 2002................................ 6,800 23.20
Fourth quarter 2002............................... 5,000 23.90
Put Options
Second quarter 2002............................... 14,000 $22.00
Third quarter 2002................................ 9,000 22.00
Fourth quarter 2002............................... 9,000 22.00
At December 31, 2001, the fair market value of these hedge positions is
$19.6 million, net of the cost of the options of $3.8 million. All of these
agreements expose us to counterparty credit risk to the extent that the
counterparty is unable to meet its settlement commitments.
26
Derivative Instruments Designated as Fair Value Hedges
In late December 2001, we entered into two interest rate swap agreements
with notional amounts totaling $150 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
$0.6 million as of December 31, 2001, with a corresponding increase in 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 $100 million, and we pay the counterparty a variable
annual rate equal to the six-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%.
Subsequent to December 31, 2001, we entered into an interest rate swap
agreement with a notional amount totaling $50 million to hedge the fair value
of our 9 3/8% Notes. Under the terms of this agreement, the counterparty pays
us a weighted average fixed annual rate of 9 3/8% on the notional amount of
$50 million, and we pay the counterparty a variable annual rate equal to the
three-month LIBOR rate plus a weighted average rate of 3.49%.
Fair Values of Financial Instruments
Fair value for cash, short-term investments, receivables and payables
approximates carrying value. The following table details the carrying values
and approximate fair values of our other investments, derivative financial
instruments and long-term debt at December 31, 2001 and 2000.
December 31, 2001 December 31, 2000
----------------------------------------
Carrying Approximate Carrying Approximate
Amount Fair Value Amount Fair Value
-------- ----------------------------
(In thousands)
Other investments................ $ -- $ -- $ 78 $ 78
Derivative Instruments
Option commodity contracts..... 9,490 9,490 5,595 11,088
Commodity price swaps.......... 10,120 10,120 -- (32,253)
Interest rate swaps............ (633) (633) -- --
Long-term debt (see Note 12)..... 450,444 436,012 409,727 412,823
TECONS........................... 115,000 68,770 115,000 60,950
The fair value of our long-term debt and TECONS were determined based upon
interest rates currently available to us for borrowing with similar terms at
December 31, 2001 and 2000.
Other--Enron Exposure and Call Spreads
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. As a result, we recorded a $7.6 million charge in the fourth
quarter of 2001: $1.2 million related to the November and December 2001 crude
oil price swaps, $0.9 million related to the Enron call spread (see below),
and $5.5 million related to the fair value of open hedges of second, third and
fourth quarter 2002 crude oil production. 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 December 31, 2001, 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, in the next 12 months.
27
In 2001 and 2000, we entered into call spreads with the anticipation of
using the proceeds to offset the Unocal Contingent payment. (See Note 17).
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. (See above
discussion). 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. At December 31, 2001, $1.1 million is reflected in other long-term
liabilities.
17. Contingent Payment and Price Sharing Agreements
In connection with the acquisition from Unocal in 1996 of the properties
located in California, we are obligated to make a contingent payment for the
years 1998 through 2004 if oil prices exceed thresholds set forth in the
agreement with Unocal. Any contingent payment will be accounted for as a
purchase price adjustment to oil and gas properties. The contingent payment
will equal 50% of the difference between the actual average annual price
received on a field-by-field basis (capped by a maximum price) and a minimum
price, less ad valorem and production taxes, multiplied by the actual number
of barrels of oil sold that are produced from the properties acquired from
Unocal during the respective year. The minimum price of $17.75 per Bbl under
the agreement (determined based on the near month delivery of WTI crude oil on
the NYMEX) is escalated at 3% per year and the maximum price of $21.75 per Bbl
on the NYMEX is escalated at 3% per year. Minimum and maximum prices are
reduced to reflect the field level price by subtracting a fixed differential
established for each field. The reduction was established at approximately the
differential between actual sales prices and NYMEX prices in effect in 1995
($4.34 per Bbl weighted average for all the properties acquired from Unocal).
We accumulate credits to offset the contingent payment when prices are $.50
per Bbl or more below the minimum price. We paid $10.8 million to Unocal under
this agreement on March 15, 2002.
In connection with the acquisition of the Congo properties in 1995, we
entered into a price sharing agreement with the seller. There is no
termination date associated with this agreement. Under the terms of the
agreement, if the average price received for the oil production during the
year is greater than the benchmark price established by the agreement, we are
obligated to pay the seller 50% of the difference between the benchmark price
and the actual price received, for all the barrels associated with this
acquisition. The benchmark price was $15.78 per Bbl for 2001, $15.19 per Bbl
for 2000 and $14.79 per Bbl for 1999. The benchmark price increases each year,
based on the increase in the Consumer Price Index. For 2001, the effect of
this agreement was that we only owned upside above $15.78 per Bbl on
approximately 56% of our Congo production. We were obligated to pay the seller
$3.4 million in 2001 and $5.4 million in 2000 under this price sharing
agreement. This obligation was accounted for as a reduction in oil revenues.
No payment was due in 1999.
We acquired a 12% working interest in the Point Pedernales oil field from
Unocal in 1994 and the remainder of its 80.3 % working interest from Torch in
1996. We are entitled to all revenue proceeds up to $9.00 per Bbl, with the
excess revenue over $9.00 per Bbl, if any, we share with the original owners
from whom Torch acquired its interest. We own amounts below $9.00 per Bbl with
the other working interest owners based on their respective ownership
interests. For 2001, the effect of this agreement is we were entitled to
receive the pricing upside above $9.00 per Bbl on approximately 73% of the
gross Point Pedernales production. As of December 31, 2001, we had $0.2
million accrued as our obligation under this agreement. As of December 31,
2000, we had $0.6 million accrued as our obligation under this agreement. As
of December 31, 1999, we had $5.1 million accrued as our obligation under this
agreement.
18. Supplemental Information (Unaudited)
Oil and Gas Producing Activities
Included herein is information with respect to oil and gas acquisition,
exploration, development and production activities, which is based on
estimates of year-end oil and gas reserve quantities and estimates of future
development costs and production schedules. Reserve quantities and future
production as of December 31,
28
2001, and for previous years, are based primarily on reserve reports prepared
by the independent petroleum engineering firm of Ryder Scott Company. These
estimates are inherently imprecise and subject to substantial revision.
Estimates of future net cash flows from proved reserves of gas, oil,
condensate and natural gas liquids ("NGL") were made in accordance with SFAS
No. 69, Disclosures about Oil and Gas Producing Activities. The estimates are
based on NYMEX prices at year-end 2001, of $19.84 per Bbl and $2.57 per MMbtu,
and are adjusted for the effects of contractual agreements with Unocal and
Amoco in connection with the California and Congo property acquisitions (see
Note 17).
Estimated future cash inflows are reduced by estimated future development
and production costs based on year-end cost levels, assuming continuation of
existing economic conditions, and by estimated future income tax expense. Tax
expense is calculated by applying the existing statutory tax rates, including
any known future changes, to the pre-tax net cash flows, less depreciation of
the tax basis of the properties and depletion allowances applicable to the
gas, oil, condensate and NGL production. Because the disclosure requirements
are standardized, significant changes can occur in these estimates based upon
oil and gas prices currently in effect. The results of these disclosures
should not be construed to represent the fair market value of our oil and gas
properties. A market value determination would include many additional factors
including: (i) anticipated future increases or decreases in oil and gas prices
and production and development costs; (ii) an allowance for return on
investment; (iii) the value of additional reserves, not considered proved at
the present, which may be recovered as a result of further exploration and
development activities; and (iv) other business risks.
29
Costs incurred
The following table sets forth the costs incurred in property acquisition
and development activities:
Year Ended December 31,
--------------------------
2001 2000 1999
----------------------
(In thousands)
Domestic
Property acquisition
Proved properties............................ $ 41,135 $ -- $ 62,300
Unproved properties (/1/).................... 6,131 4,892 520
Exploration.................................... 16,004 5,591 4,973
Development
Proved reserves.............................. 95,005 79,857 35,372
Unproved reserves............................ 5,716 11,433 2,906
----------------------
$163,991 $101,773 $106,071
======== ======== ========
Foreign
Property acquisition
Proved properties............................ $ -- $ -- $ --
Unproved properties (/1/).................... 47 479 424
Exploration.................................... 4,703 6,467 3,742
Development
Proved reserves.............................. 20,222 4,406 20,404
Unproved reserves............................ -- 342 --
----------------------
$ 24,972 $ 11,694 $ 24,570
======== ======== ========
Total
Property acquisition
Proved properties............................ $ 41,135 $ -- $ 62,300
Unproved properties (/1/).................... 6,178 5,371 944
Exploration.................................... 20,707 12,058 8,715
Development
Proved reserves.............................. 115,227 84,263 55,776
Unproved reserves............................ 5,716 11,775 2,906
----------------------
$188,963 $113,467 $130,641
======== ======== ========
- --------
(/1/Includes)capitalized interest directly related to development activities of
$2.5 million and $0.3 million in 2001 and 1999.
30
Capitalized costs
The following table sets forth the capitalized costs relating to oil and gas
activities and the associated accumulated depreciation, depletion and
amortization:
As of December 31,
----------------------------------
2001 2000 1999
---------- ---------- ----------
(In thousands)
Domestic
Proved properties........................ $ 893,215 $ 986,889 $ 898,032
Unproved properties...................... 27,117 25,341 21,755
---------- ---------- ----------
Total capitalized costs................ 920,332 1,012,230 919,787
Accumulated depreciation, depletion and
amortization.......................... (378,644) (461,225) (403,727)
---------- ---------- ----------
Net capitalized costs................ $ 541,688 $ 551,005 $ 516,060
========== ========== ==========
Foreign
Proved properties........................ $ 91,437 $ 84,558 $ 80,374
Unproved properties...................... 2,660 5,445 2,618
---------- ---------- ----------
Total capitalized costs................ 94,097 90,003 82,992
Accumulated depreciation, depletion and
amortization.......................... (37,693) (29,008) (20,901)
---------- ---------- ----------
Net capitalized costs................ $ 56,404 $ 60,995 $ 62,091
========== ========== ==========
Total
Proved properties........................ $ 984,652 $1,071,447 $ 978,406
Unproved properties...................... 29,777 30,786 24,373
---------- ---------- ----------
Total capitalized costs................ 1,014,429 1,102,233 1,002,779
Accumulated depreciation, depletion and
amortization.......................... (416,337) (490,233) (424,628)
---------- ---------- ----------
Net capitalized costs................ $ 598,092 $ 612,000 $ 578,151
========== ========== ==========
31
Results of operations for producing activities
Year Ended December 31,(1)
-------------------------------
2001 2000 1999
--------- --------- ---------
(In thousands)
Domestic
Revenues from oil and gas producing
activities................................. $ 309,019 $ 265,917 $ 195,032
Production costs............................ (161,086) (130,671) (111,327)
Exploration costs........................... (16,170) (5,503) (10,643)
Depreciation, depletion and amortization.... (61,331) (51,960) (62,360)
Provision for impairment of oil and gas
properties................................. (89,466) -- --
Income tax (provision) benefit.............. 7,645 (31,336) (2,795)
--------- --------- ---------
Results of operations from producing
activities (excluding corporate overhead
and interest costs)...................... $ (11,389) $ 46,447 $ 7,907
========= ========= =========
Foreign
Revenues from oil and gas producing
activities................................. $ 36,020 $ 40,944 $ 30,664
Production costs............................ (14,028) (13,641) (12,869)
Exploration costs........................... (5,888) (4,271) (3,374)
Depreciation, depletion and amortization.... (10,381) (8,085) (9,177)
Provision for impairment of oil and gas
properties................................. (14,024) -- --
Income tax (provision) benefit.............. 3,318 (6,036) (1,082)
--------- --------- ---------
Results of operations from producing
activities (excluding corporate overhead
and interest costs)...................... $ (4,983) $ 8,911 $ 4,162
========= ========= =========
Total
Revenues from oil and gas producing
activities................................. $ 345,039 $ 306,861 $ 225,696
Production costs............................ (175,114) (144,312) (124,196)
Exploration costs........................... (22,058) (9,774) (14,017)
Depreciation, depletion and amortization.... (71,712) (60,045) (71,537)
Provision for impairment of oil and gas
properties................................. (103,490) -- --
Income tax (provision) benefit.............. 10,963 (37,372) (3,877)
--------- --------- ---------
Results of operations from producing
activities (excluding corporate overhead
and interest costs)...................... $ (16,372) $ 55,358 $ 12,069
========= ========= =========
- --------
(1) Reflects our continuing operations.
32
Our estimated total proved and proved developed reserves of oil and gas are
as follows:
Year Ended December 31,
--------------------------------------------------------
2001 2000 1999
----------------- ----------------- ------------------
Oil(/1/) Gas Oil(/1/) Gas Oil(/1/) Gas
(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf)
-------- ------- -------- ------- -------- --------
Domestic
Proved reserves at
beginning of year.... 196,692 165,977 239,190 145,125 164,300 403,256
Revisions of previous
estimates............ 15,164 (55,422) (40,340) 20,740 61,168 56,097
Extensions and
discoveries.......... 311 578 15,945 17,678 10,795 11,800
Production............ (14,536) (12,750) (15,591) (15,215) (15,892) (17,620)
Sales of reserves in-
place................ -- -- (2,512) (2,351) (10,270) (335,927)
Purchase of reserves
in-place............. 1,383 12,980 -- -- 29,089 27,519
------- ------- ------- ------- ------- --------
Proved reserves at end
of year.............. 199,014 111,363 196,692 165,977 239,190 145,125
======= ======= ======= ======= ======= ========
Proved developed
reserves
Beginning of year... 160,039 122,500 174,846 112,204 123,077 308,667
======= ======= ======= ======= ======= ========
End of year......... 169,507 92,890 160,039 122,500 174,846 112,204
======= ======= ======= ======= ======= ========
Foreign
Proved reserves at
beginning of year.... 23,202 -- 26,048 -- 25,841 --
Revisions of previous
estimates............ (5,478) -- (1,003) -- 2,042 --
Extensions and
discoveries.......... -- 1,129 -- -- -- --
Production............ (1,880) -- (1,843) -- (1,835) --
Sales of reserves in-
place................ -- -- -- -- -- --
Purchase of reserves
in-place............. -- -- -- -- -- --
------- ------- ------- ------- ------- --------
Proved reserves at end
of year.............. 15,844 1,129 23,202 -- 26,048 --
======= ======= ======= ======= ======= ========
Proved developed
reserves
Beginning of year... 11,013 -- 13,749 -- 10,242 --
======= ======= ======= ======= ======= ========
End of year......... 15,844 1,129 11,013 -- 13,749 --
======= ======= ======= ======= ======= ========
Total(2)
Proved reserves at
beginning of year.... 219,894 165,977 265,238 145,125 190,141 403,256
Revisions of previous
estimates............ 9,686 (55,422) (41,343) 20,740 63,210 56,097
Extensions and
discoveries.......... 311 1,707 15,945 17,678 10,795 11,800
Production............ (16,416) (12,750) (17,434) (15,215) (17,727) (17,620)
Sales of reserves in-
place................ -- -- (2,512) (2,351) (10,270) (335,927)
Purchase of reserves
in-place............. 1,383 12,980 -- -- 29,089 27,519
------- ------- ------- ------- ------- --------
Proved reserves at end
of year.............. 214,858 112,492 219,894 165,977 265,238 145,125
======= ======= ======= ======= ======= ========
Proved developed
reserves
Beginning of year... 171,052 122,500 188,595 112,204 133,319 308,667
======= ======= ======= ======= ======= ========
End of year......... 185,351 94,019 171,052 122,500 188,595 112,204
======= ======= ======= ======= ======= ========
- --------
(/1/Includes)estimated NGL reserves.
(2) Reserves from our discontinued operations are included in this table.
33
Discounted future net cash flows
The standardized measure of discounted future net cash flows and changes
therein are shown below:
Year Ended December 31,
-------------------------------------
2001 2000 1999
----------- ----------- -----------
(In thousands)
Domestic
Future cash inflows................... $ 3,182,420 $ 6,168,033 $ 4,823,952
Future production costs............... (1,773,397) (2,968,448) (2,132,655)
Future development costs.............. (382,412) (349,150) (357,708)
----------- ----------- -----------
Future net inflows before income tax.. 1,026,611 2,850,435 2,333,589
Future income taxes................... (149,564) (896,974) (704,236)
----------- ----------- -----------
Future net cash flows................. 877,047 1,953,461 1,629,353
10% discount factor................... (366,050) (803,899) (739,181)
----------- ----------- -----------
Standardized measure of discounted
future net cash flows................ $ 510,997 $ 1,149,562 $ 890,172
=========== =========== ===========
Foreign
Future cash inflows................... $ 248,569 $ 521,831 $ 469,327
Future production costs............... (123,628) (235,825) (177,150)
Future development costs.............. (6,863) (54,475) (46,750)
----------- ----------- -----------
Future net inflows before income tax.. 118,078 231,531 245,427
Future income taxes................... (25,237) (70,452) (66,971)
----------- ----------- -----------
Future net cash flows................. 92,841 161,079 178,456
10% discount factor................... (24,152) (55,752) (61,455)
----------- ----------- -----------
Standardized measure of discounted
future net cash flows................ $ 68,689 $ 105,327 $ 117,001
=========== =========== ===========
Total
Future cash inflows................... $ 3,430,989 $ 6,689,864 $ 5,293,279
Future production costs............... (1,897,025) (3,204,273) (2,309,805)
Future development costs.............. (389,275) (403,625) (404,458)
----------- ----------- -----------
Future net inflows before income tax.. 1,144,689 3,081,966 2,579,016
Future income taxes................... (174,801) (967,426) (771,207)
----------- ----------- -----------
Future net cash flows................. 969,888 2,114,540 1,807,809
10% discount factor................... (390,202) (859,651) (800,636)
----------- ----------- -----------
Standardized measure of discounted
future net cash flows................ $ 579,686 $ 1,254,889 $ 1,007,173
=========== =========== ===========
- --------
* In addition to the information presented in the above table, we entered into
swap and option arrangements on a portion of our future crude production as
of December 31, 2001 (see Note 16). The effects of these hedges would
increase the present value of future net cash flows discounted at a 10% rate
("PV-10") by approximately $17.8 million as of December 31, 2001.
34
The following are the principal sources of change in the standardized
measure of discounted future net cash flows:
Year Ended December 31,
----------------------------------
2001 2000 1999
---------- ---------- ----------
Domestic
Standardized measure--beginning of year.. $1,149,562 $ 890,172 $ 277,963
Sales, net of production costs........... (154,785) (147,924) (94,384)
Purchases of reserves in-place........... 13,759 -- 224,251
Net change in prices and production
costs................................... (904,288) 387,009 439,615
Extensions, discoveries and improved
recovery, net of future production and
development costs....................... 2,750 181,885 59,873
Changes in estimated future development
costs................................... (61,735) (8,806) (12,375)
Development costs incurred............... 62,562 79,857 32,380
Revisions of quantity estimates.......... 20,906 (233,132) 276,965
Accretion of discount.................... 151,060 110,162 27,796
Net change in income taxes............... 211,477 (149,592) (211,448)
Sales of reserves in-place............... -- (9,242) (151,348)
Changes in production rates and other.... 19,729 49,173 20,884
---------- ---------- ----------
Standardized measure--end of year........ $ 510,997 $1,149,562 $ 890,172
========== ========== ==========
Foreign
Standardized measure--beginning of year.. $ 105,327 $ 117,001 $ 21,970
Sales, net of production costs........... (21,899) (27,255) (17,759)
Purchases of reserves in-place........... -- -- --
Net change in prices and production
costs................................... (56,360) 19,595 59,641
Extensions, discoveries and improved
recovery, net of future production and
development costs....................... 114 -- --
Changes in estimated future development
costs................................... 16,455 (7,167) 12,711
Development costs incurred............... 16,100 4,406 7,175
Revisions of quantity estimates.......... (25,804) (7,204) 8,479
Accretion of discount.................... 13,861 14,300 2,197
Net change in income taxes............... 24,150 (7,284) (26,001)
Sales reserves in-place.................. -- -- --
Changes in production rates and other.... (3,255) (1,065) 48,588
---------- ---------- ----------
Standardized measure--end of year........ $ 68,689 $ 105,327 $ 117,001
========== ========== ==========
Total
Standardized measure--beginning of year.. $1,254,889 $1,007,173 $ 299,933
Sales, net of production costs........... (176,684) (175,179) (112,143)
Purchases of reserves in-place........... 13,759 -- 224,251
Net change in prices and production
costs................................... (960,648) 406,604 499,256
Extensions, discoveries and improved
recovery, net of future production and
development costs....................... 2,864 181,885 59,873
Changes in estimated future development
costs................................... (45,280) (15,973) 336
Development costs incurred............... 78,662 84,263 39,555
Revisions of quantity estimates.......... (4,898) (240,336) 285,444
Accretion of discount.................... 164,921 124,462 29,993
Net change in income taxes............... 235,627 (156,876) (237,449)
Sales of reserves in-place............... -- (9,242) (151,348)
Changes in production rates and other.... 16,474 48,108 69,472
---------- ---------- ----------
Standardized measure--end of year........ $ 579,686 $1,254,889 $1,007,173
========== ========== ==========
- --------
* In addition to the information presented in the above table, the Company had
entered into swap and option arrangements on a portion of its future crude
production as of December 31, 2001 (see Note 16). The effects of these
hedges would increase the PV-10 by approximately $17.8 million as of
December 31, 2001.
35
20. Selected Quarterly Financial Data (Unaudited)
Quarterly Results Restated --
<Table>
<Caption>
Income
(Loss) From Cumulative
Income (Loss) Discontinued Effect of
Income From Operations, Change in Net
(Loss) From Continuing Net of Accounting Income
Revenues Operations Operations Income Tax Principle (Loss)
-------- ----------- ------------- ------------ ---------- --------
(Expressed in thousands except per share amounts)
2001
First Quarter $105,186 $ 25,888 $ 8,185 $1,418 $ -- $ 9,603
Second Quarter 93,273 14,865 1,781 878 -- 2,659
Third Quarter 80,059 7,367 (2,783) 400 -- (2,383)
Fourth Quarter(3) 66,794 (136,773) (89,114) 64 -- (89,050)
-------- --------- -------- ------ ----- --------
$345,312 $ (88,653) $(81,931) $2,760 $ -- $(79,171)
======== ========= ======== ====== ===== ========
2000(2)
First Quarter $ 66,603 $ 9,743 $ (58) $ 709 $ -- $ 651
Second Quarter 66,289 7,429 (1,563) 823 (796) (1,536)
Third Quarter 82,411 23,016 7,288 1,367 -- 8,655
Fourth Quarter 93,916 16,014 2,722 1,143 -- 3,865
-------- --------- -------- ------ ----- --------
$309,219 $ 56,202 $ 8,389 $4,042 $(796) $ 11,635
======== ========= ======== ====== ===== ========
</Table>
<Table>
<Caption>
Basic Earnings (Loss) Per Share(1)
-----------------------------------------------
Net
Continuing Discontinued Cumulative Income
Operations Operations Effect (Loss)
---------- ------------ ---------- ------
2001
First Quarter $ 0.50 $0.08 $ -- $ 0.58
Second Quarter 0.11 0.05 -- 0.16
Third Quarter (0.16) 0.02 -- (0.14)
Fourth Quarter $(5.28) $ -- $ -- $(5.28)
2000(2)
First Quarter $ -- $0.04 $ -- $ 0.04
Second Quarter (0.09) 0.04 (0.04) (0.09)
Third Quarter 0.41 0.08 -- 0.49
Fourth Quarter $ 0.16 $0.06 $ -- $ 0.22
</Table>
<Table>
<Caption>
Diluted Earnings (Loss) Per Share(1)
-----------------------------------------------
Net
Continuing Discontinued Cumulative Income
Operations Operations Effect (Loss)
---------- ------------ ---------- ------
2001
First Quarter $ 0.48 $0.08 $ -- $ 0.56
Second Quarter 0.10 0.06 -- 0.16
Third Quarter (0.16) 0.02 -- (0.14)
Fourth Quarter $(5.28) $ -- $ -- $(5.28)
2000(2)
First Quarter $ -- $0.04 $ -- $ 0.04
Second Quarter (0.09) 0.04 (0.04) (0.09)
Third Quarter 0.41 0.07 -- 0.48
Fourth Quarter $ 0.15 $0.07 $ -- $ 0.22
</Table>
- --------
(/1/The)sum of the individual quarterly net income (loss) per common share may
not agree with year-to-date net income (loss) per common share as each
quarterly computation is based on the weighted average number of common
shares outstanding during that period.
(/2/Results)for the 2000 quarters were revised due to a change in accounting
for processed fuel oil and natural gas liquids inventories (see Note 2).
(3) Fourth quarter 2002 results include $103.5 million of impairments.
21. Subsequent Events
Discontinued Operations
In 2002, we sold a majority of our oil and gas properties located in Texas,
Alabama and Louisiana for approximately $9.0 million, and recognized a $0.5
million loss on the sale of these properties. Historical results of operations
from these properties are classified as discontinued operations in our
statements of income. Revenues associated with the sold properties were $8.3
million in 2001, $14.6 million in 2000 and $8.5 million in 1999.
Acquisition
Effective September 18, 2002, pursuant to an Agreement and Plan of Merger, a
wholly owned subsidiary of Nuevo Energy Company was merged with and into Athanor
Resources, Inc. ("Athanor"), a Delaware corporation, and Athanor became the
surviving wholly owned subsidiary of Nuevo Energy Company. In connection with
the merger, Nuevo issued approximately 2.0 million shares of common stock for
all of the common and preferred stock of Athanor. The merger was accounted for
using the purchase method of accounting. The purchase price totaling
approximately $101.4 million included a combination of $61.3 million of
available cash and additional borrowings, the issuance of approximately $20.1
million of our common stock to Athanor stockholders.
Legal Proceedings
Legal Update
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 owed a 50% interest in the Sacate
field, offshore Santa Barbara County, California. We believed that we had been
denied a reasonable opportunity to exercise our rights under the unit operating
agrement. 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 in the second quarter of 2002.
On September 22, 2000, we were named as a defendant in the lawsuit Thomas
Wachtell et al versus Nuevo Energy Company in the Superior Court of Los Angeles
County, California. We successfully removed this lawsuit to the United States
District Court for the Central District of California. The plaintiffs, who own
interests in the Point Pedernales properties, asserted numerous causes of action
including breach of contract, fraud and conspiracy in connection with the
plaintiffs' allegation that: (i) royalties had not been properly paid to them
for production from the Point Pedernales field, (ii) payments had not been made
to them related to production from the Pescado and Sacate fields and (iii) we
had failed to recognize the plaintiffs interests in the Tranquillon Ridge
project. We settled this lawsuit in June 2002 for, among other matters, making a
payment to plaintiffs of $3.4 million, and receiving from plaintiffs certain
interests in properties and extinguishing certain contract rights of plaintiffs.
We established a reserve for this contingency in 2001 and the settlement payment
did not have a material impact on our results of operations or financial
position.
36
GLOSSARY OF OIL AND GAS TERMS
Terms used to describe quantities of oil and natural gas
. Bbl--One stock tank barrel, or 42 US gallons liquid volume, of crude oil
or other liquid hydrocarbons.
. Bcf--One billion cubic feet of natural gas.
. Bcfe--One billion cubic feet of natural gas equivalent.
. BOE--One barrel of oil equivalent, converting gas to oil at the ratio of
6 Mcf of gas to 1 Bbl of oil.
. BOPD--One barrel of oil per day.
. MBbl--One thousand Bbls.
. Mcf--One thousand cubic feet of natural gas.
. MMBbl--One million Bbls of oil or other liquid hydrocarbons.
. MMcf--One million cubic feet of natural gas.
. MBOE--One thousand BOE.
. MMBOE--One million BOE.
Terms used to describe the Company's interests in wells and acreage
. Gross oil and gas wells or acres--The Company's gross wells or gross
acres represent the total number of wells or acres in which the Company
owns a working interest.
. Net oil and gas wells or acres--Determined by multiplying "gross" oil
and natural gas wells or acres by the working interest that the Company
owns in such wells or acres represented by the underlying properties.
Terms used to assign a present value to the Company's reserves
. Standard measure of proved reserves--The present value, discounted at
10%, of the pre-tax future net cash flows attributable to estimated net
proved reserves. The Company calculates this amount by assuming that it
will sell the oil and gas production attributable to the proved reserves
estimated in its independent engineer's reserve report for the prices it
received for the production on the date of the report, unless it had a
contractual arrangement specific to a property to sell the production
for a different price. The Company also assumes that the cost to produce
the reserves will remain constant at the costs prevailing on the date of
the report. The assumed costs are subtracted from the assumed revenues
resulting in a stream of future net cash flows. Estimated future income
taxes using rates in effect on the date of the report are deducted from
the net cash flow stream. The after-tax cash flows are discounted at 10%
to result in the standardized measure of the Company's proved reserves.
The standardized measure of the Company's proved reserves is disclosed
in the Company's audited financial statements in Note 14.
. Pre-tax discounted present value--The discounted present value of proved
reserves is identical to the standardized measure, except that estimated
future income taxes are not deducted in calculating future net cash
flows. The Company discloses the discounted present value without
deducting estimated income taxes to provide what it believes is a better
basis for comparison of its reserves to the producers who may have
different tax rates.
Terms used to classify our reserve quantities
. Proved reserves--The estimated quantities of crude oil, natural gas and
natural gas liquids which, upon analysis of geological and engineering
data, appear with reasonable certainty to be recoverable in the future
from known oil and natural gas reservoirs under existing economic and
operating conditions.
38
The SEC definition of proved oil and gas reserves, per Article 4-10(a)(2)
of Regulation S-X, is as follows:
Proved oil and gas reserves. Proved oil and gas reserves are the
estimated quantities of crude oil, natural gas, and natural gas liquids
which geological and engineering data demonstrate with reasonable certainty
to be recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e., prices and costs as of the date
the estimate is made. Prices include consideration of changes in existing
prices provided only by contractual arrangements, but not on escalations
based upon future conditions.
(a) Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The
area of a reservoir considered proved includes (A) that portion delineated
by drilling and defined by gas-oil and/or oil-water contacts, if any; and
(B) the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.
(b) Reserves which can be produced economically through application of
improved recovery, techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for
the engineering analysis on which the project or program was based.
(c) Estimates of proved reserves do not include the following: (1) oil
that may become available from known reservoirs, but is classified
separately as "indicated additional reserves"; (2) crude oil, natural gas,
and natural gas liquids, the recovery of which is subject to reasonable
doubt because of uncertainty as to geology, reservoir characteristics, or
economic factors; (3) crude oil, natural gas, and natural gas liquids, that
may occur in undrilled prospects; and (4) crude oil, natural gas, and
natural gas liquids, that may be recovered from oil shales, coal, gilsonite
and other such sources.
. Proved developed reserves--Proved reserves that can be expected to be
recovered through existing wells with existing equipment and operating
methods.
. Proved undeveloped reserves--Proved reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells
where a relatively major expenditure is required.
Terms which describe the cost to acquire the Company's reserves
. Finding costs--The Company's finding costs compare the amount the
Company spent to acquire, explore and develop its oil and gas
properties, explore for oil and gas and to drill and complete wells
during a period, with the increases in reserves during the period. This
amount is calculated by dividing the net change in the Company's
evaluated oil and property costs during a period by the change in proved
reserves plus production over the same period. The Company's finding
costs as of December 31 of any year represent the average finding costs
over the three-year period ending December 31 of that year.
Terms which describe the productive life of a property or group of properties
. Reserve life index--A measure of the productive life of an oil and gas
property or a group of oil and gas properties, expressed in years.
Reserve life index for the years ended December 31, 2001, 2000 or 1999
equal the estimated net proved reserves attributable to a property or
group of properties divided by production from the property or group of
properties for the four fiscal quarters preceding the date as of which
the proved reserves were estimated.
Terms used to describe the legal ownership of the Company's oil and gas
properties
. Royalty interest--A real property interest entitling the owner to
receive a specified portion of the gross proceeds of the sale of oil and
natural gas production or, if the conveyance creating the interest
provides,
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a specific portion of oil and natural gas produced, without any deduction
for the costs to explore for, develop or produce the oil and natural gas.
A royalty interest owner has no right to consent to or approve the
operation and development of the property, while the owners of the
working interests have the exclusive right to exploit the mineral on the
land.
. Working interest--A real property interest entitling the owner to
receive a specified percentage of the proceeds of the sale of oil and
natural gas production or a percentage of the production, but requiring
the owner of the working interest to bear the cost to explore for,
develop and produce such oil and natural gas. A working interest owner
who owns a portion of the working interest may participate either as
operator or by voting his percentage interest to approve or disapprove
the appointment of an operator and drilling and other major activities
in connection with the development and operation of a property.
. Net revenue interest--A real property interest entitling the owner to
receive a specified percentage of the proceeds of the sale of oil and
natural gas production or a percentage of the production, net of royalty
interests and costs to explore for, develop and produce such oil and
natural gas.
Terms used to describe seismic operations
. Seismic data--Oil and gas companies use seismic data as their principal
source of information to locate oil and gas deposits, both to aid in
exploration for new deposits and to manage or enhance production from
known reservoirs. To gather seismic data, an energy source is used to
send sound waves into the subsurface strata. These waves are reflected
back to the surface by underground formations, where they are detected
by geophones which digitize and record the reflected waves. Computers
are then used to process the raw data to develop an image of underground
formations.
. 2-D seismic data--2-D seismic survey data has been the standard
acquisition technique used to image geologic formations over a broad
area. 2-D seismic data is collected by a single line of energy sources
which reflect seismic waves to a single line of geophones. When
processed, 2-D seismic data produces an image of a single vertical plane
of sub-surface data.
. 3-D seismic--3-D seismic data is collected using a grid of energy
sources, which are generally spread over several miles. A 3-D survey
produces a three dimensional image of the subsurface geology by
collecting seismic data along parallel lines and creating a cube of
information that can be divided into various planes, thus improving
visualization. Consequently, 3-D seismic data is a more reliable
indicator of potential oil and natural gas reservoirs in the area
evaluated than 2-D seismic data.
The Company's miscellaneous definitions
. Infill drilling--Infill drilling is the drilling of an additional well
or additional wells in excess of those provided for by a spacing order
in order to more adequately drain a reservoir.
. No. 6 fuel oil (Bunker)--No. 6 fuel oil is a heavy residual fuel oil
used by ships, industry, and for large-scale heating installations.
. Upstream oil and gas properties--Upstream is a term used in describing
operations performed before those at a point of reference. Production is
an upstream operation and marketing is a downstream operation when the
refinery is used as a point of reference. On a gas pipeline, gathering
activities are considered to have ended when gas reaches a central point
for delivery into a single line, and facilities used before this point
of reference are upstream facilities used in gathering, whereas
facilities employed after commingling at the central point and employed
to make ultimate delivery of the gas are downstream facilities.
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