1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q/A
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2000
Commission File Number 1-10537
NUEVO ENERGY COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE 76-0304436
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
1021 MAIN STREET, SUITE 2100
HOUSTON, TEXAS 77002
(Address of Principal Executive Offices) (Zip Code)
Registrant's telephone number, including area code: (713) 652-0706
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the Registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
--- ---
As of August 10, 2000, the number of outstanding shares of the Registrant's
common stock was 17,587,238.
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NUEVO ENERGY COMPANY
INDEX
PAGE
NUMBER
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
Condensed Consolidated Balance Sheets:
June 30, 2000 (Unaudited) and December 31, 1999 .................................. 3
Condensed Consolidated Statements of Operations (Unaudited):
Three and six months ended June 30, 2000 and June 30, 1999 ....................... 4
Condensed Consolidated Statements of Cash Flows (Unaudited):
Six months ended June 30, 2000 and June 30, 1999 ................................. 6
Notes to Condensed Consolidated Financial Statements (Unaudited) ....................... 7
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations ...... 14
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk ................................. 25
PART II. OTHER INFORMATION .......................................................................... 26
2
3
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Amounts in Thousands, Except Share Data)
June 30, 2000 December 31, 1999
------------- -----------------
(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents .................................................... $ 13,122 $ 10,288
Accounts receivable .......................................................... 36,554 45,004
Product inventory ............................................................ 11,135 4,610
Prepaid expenses and other ................................................... 4,961 6,389
----------- -----------
Total current assets ....................................................... 65,772 66,291
----------- -----------
PROPERTY AND EQUIPMENT, AT COST:
Land ......................................................................... 51,017 51,017
Oil and gas properties (successful efforts method) ........................... 1,045,774 1,002,779
Gas plant facilities ......................................................... 12,020 12,140
Other facilities ............................................................. 12,595 11,874
----------- -----------
1,121,406 1,077,810
Accumulated depreciation, depletion and amortization ......................... (461,191) (429,349)
----------- -----------
660,215 648,461
----------- -----------
DEFERRED TAX ASSETS, NET ...................................................... 22,971 24,005
OTHER ASSETS .................................................................. 20,284 21,273
----------- -----------
$ 769,242 $ 760,030
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable ........................................................... $ 14,667 $ 20,492
Accrued interest ........................................................... 2,474 2,353
Accrued liabilities ........................................................ 40,304 37,755
Current maturities of long-term debt ....................................... -- 750
----------- -----------
Total current liabilities ............................................... 57,445 61,350
----------- -----------
LONG-TERM DEBT, NET OF CURRENT MATURITIES ..................................... 363,227 340,750
OTHER LONG-TERM LIABILITIES ................................................... 8,447 9,292
CONTINGENCIES
COMPANY-OBLIGATED MANDATORILY REDEEMABLE CONVERTIBLE PREFERRED
SECURITIES OF NUEVO FINANCING I ............................................ 115,000 115,000
STOCKHOLDERS' EQUITY:
Common stock, $.01 par value, 50,000,000 shares authorized,
20,589,072 and 20,437,371 shares issued and 17,421,594
and 17,931,393 shares outstanding at June 30, 2000 and
December 31, 1999, respectively .......................................... 206 204
Additional paid-in capital ................................................. 360,397 357,855
Treasury stock, at cost, 3,006,452 and 2,430,074 shares, at
June 30, 2000 and December 31, 1999, respectively ........................ (61,935) (49,605)
Stock held by benefit trust, 161,026 and 75,904 shares, at
June 30, 2000 and December 31, 1999, respectively ........................ (3,395) (3,184)
Deferred stock compensation ................................................ (233) (216)
Accumulated deficit ........................................................ (69,917) (71,416)
----------- -----------
Total stockholders' equity ............................................ 225,123 233,638
----------- -----------
$ 769,242 $ 760,030
=========== ===========
See accompanying notes to condensed consolidated financial statements.
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NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in Thousands, Except per Share Data)
Three Months Ended June 30,
---------------------------
2000 1999
-------- --------
REVENUES:
Oil and gas revenues ............................................... $ 72,599 $ 52,876
Gain on sale of assets, net ........................................ 366 (1,387)
Interest and other income .......................................... 195 1,371
-------- --------
73,160 52,860
-------- --------
COSTS AND EXPENSES:
Lease operating expenses ........................................... 34,273 30,298
Exploration costs .................................................. 1,488 7,874
Depreciation, depletion and amortization ........................... 15,582 22,937
General and administrative expenses ................................ 4,101 3,367
Outsourcing fees ................................................... 3,430 3,636
Interest expense ................................................... 8,517 8,401
Dividends on Guaranteed Preferred
Beneficial Interests in Company's
Convertible Debentures (TECONS) ................................. 1,653 1,653
Other expense ...................................................... 2,687 457
-------- --------
71,731 78,623
-------- --------
Income (loss) before income taxes ..................................... 1,429 (25,763)
Provision (benefit) for income taxes .................................. 575 (10,205)
-------- --------
NET INCOME (LOSS) ..................................................... $ 854 $(15,558)
======== ========
EARNINGS (LOSS) PER SHARE:
BASIC:
Earnings (loss) per common share ...................................... $ 0.05 $ (0.78)
======== ========
Weighted average common shares outstanding ............................ 17,587 19,853
======== ========
DILUTED:
Earnings (loss) per common share ...................................... $ 0.05 $ (0.78)
======== ========
Weighted average common and dilutive potential
common shares outstanding ............................................. 17,939 19,853
======== ========
See accompanying notes to condensed consolidated financial statements.
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NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in Thousands, Except per Share Data)
Six Months Ended June 30,
-------------------------
2000 1999
-------- --------
REVENUES:
Oil and gas revenues ....................................................... $143,328 $ 96,340
Gain on sale of assets, net ................................................ 506 80,312
Interest and other income .................................................. 821 2,851
-------- --------
144,655 179,503
-------- --------
COSTS AND EXPENSES:
Lease operating expenses ................................................... 65,384 60,212
Exploration costs .......................................................... 4,742 9,999
Depreciation, depletion and amortization ................................... 31,823 46,257
General and administrative expenses ........................................ 9,473 7,199
Outsourcing fees ........................................................... 6,763 6,846
Interest expense ........................................................... 16,807 16,400
Dividends on Guaranteed Preferred
Beneficial Interests in Company's
Convertible Debentures (TECONS) ......................................... 3,306 3,306
Other expense .............................................................. 3,847 2,979
-------- --------
142,145 153,198
-------- --------
Income before income taxes .................................................... 2,510 26,305
Provision for income taxes .................................................... 1,011 10,521
-------- --------
NET INCOME .................................................................... $ 1,499 $ 15,784
======== ========
EARNINGS PER SHARE:
BASIC:
Earnings per common share ..................................................... $ 0.08 $ 0.80
======== ========
Weighted average common shares outstanding .................................... 17,701 19,848
======== ========
DILUTED:
Earnings per common share ..................................................... $ 0.08 $ 0.79
======== ========
Weighted average common and dilutive potential
common shares outstanding ..................................................... 18,074 19,915
======== ========
See accompanying notes to condensed consolidated financial statements.
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NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in Thousands)
Six Months Ended June 30,
--------------------------
2000 1999
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ........................................................................... $ 1,499 $ 15,784
Adjustments to reconcile net income to
net cash provided by/(used in) operating activities:
Depreciation, depletion and amortization ................................... 31,823 46,257
Gain on sale of assets, net ................................................ (506) (80,312)
Dry hole costs ............................................................. 89 7,297
Amortization of other costs ................................................ 903 811
Deferred taxes ............................................................. 1,382 5,521
Mark to market of deferred compensation plan ............................... 24 111
Mark to market of liability management swap ................................ 371 --
Other ...................................................................... 66 120
--------- ---------
35,651 (4,411)
Changes in assets and liabilities:
Accounts receivable ............................................................ 8,450 (1,459)
Accounts payable and accrued liabilities ....................................... (3,152) (5,606)
Other .......................................................................... (4,621) (1,680)
--------- ---------
NET CASH PROVIDED BY/(USED IN) OPERATING ACTIVITIES .................................. 36,328 (13,156)
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties ............................................... (43,609) (35,497)
Acquisitions of oil and gas properties ............................................ -- (61,416)
Additions to gas plant facilities ................................................. (126) (674)
Additions to other facilities ..................................................... (721) (2,434)
Proceeds from sales of properties ................................................. 1,297 199,663
--------- ---------
NET CASH (USED IN)/PROVIDED BY INVESTING ACTIVITIES .................................. (43,159) 99,642
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings .......................................................... 32,500 120,090
Deferred financing costs .......................................................... (1,634) --
Payments of long-term debt ........................................................ (10,773) (160,340)
Treasury stock purchases .......................................................... (12,540) --
Proceeds from issuance of common stock ............................................ 2,112 --
--------- ---------
NET CASH PROVIDED BY/(USED IN) FINANCING ACTIVITIES .................................. 9,665 (40,250)
--------- ---------
Net increase in cash and cash equivalents ......................................... 2,834 46,236
Cash and cash equivalents at beginning of
period ......................................................................... 10,288 7,403
--------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD ........................................... $ 13,122 $ 53,639
========= =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of amounts capitalized) .......................................... $ 15,782 $ 15,646
Income taxes ................................................................... $ -- $ 2,250
See accompanying notes to condensed consolidated financial statements.
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NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The accompanying unaudited condensed consolidated financial statements
have been prepared in accordance with the rules and regulations of the
Securities and Exchange Commission and, therefore, do not include all
disclosures required by generally accepted accounting principles.
However, in the opinion of management, these statements include all
adjustments, which are of a normal recurring nature, necessary to
present fairly the financial position at June 30, 2000 and December 31,
1999 and the results of operations and changes in cash flows for the
periods ended June 30, 2000 and 1999. These financial statements should
be read in conjunction with the consolidated financial statements and
notes to consolidated financial statements in the 1999 Form 10-K of
Nuevo Energy Company (the "Company").
USE OF ESTIMATES
In order to prepare these financial statements in conformity with
generally accepted accounting principles, management of the Company has
made a number of estimates and assumptions relating to the reporting of
assets and liabilities and the disclosure of contingent assets and
liabilities, as well as reserve information, which affects the
depletion calculation. Actual results could differ from those
estimates.
COMPREHENSIVE INCOME
Comprehensive income includes net income and all changes in other
comprehensive income including, among other things, foreign currency
translation adjustments, and unrealized gains and losses on certain
investments in debt and equity securities. There are no differences
between comprehensive income (loss) and net income (loss) for the
periods presented.
DERIVATIVE FINANCIAL INSTRUMENTS
The Company utilizes derivative financial instruments to reduce its
exposure to decreases in the market prices of crude oil and natural
gas. Commodity derivatives utilized as hedges include futures, swap and
option contracts, which are used to hedge crude oil and natural gas
prices. Basis swaps are sometimes used to hedge the basis differential
between the derivative financial instrument index price and the
commodity field price. In order to qualify as a hedge, price movements
in the underlying commodity derivative must be highly correlated with
the hedged commodity. Settlement of gains and losses on price swap
contracts are realized monthly, generally based upon the difference
between the contract price and the average closing New York Mercantile
Exchange ("NYMEX") price and are reported as a component of oil and gas
revenues and operating cash flows in the period realized.
Gains and losses on option and futures contracts that qualify as a
hedge of firmly committed or anticipated purchases and sales of oil and
gas commodities are deferred on the balance sheet and recognized in
income and operating cash flows when the related hedged transaction
occurs. Premiums paid on option contracts are deferred in other assets
and amortized into oil and gas revenues over the terms of the
respective option contracts. Gains or losses attributable to the
termination of a derivative financial instrument are deferred on the
balance sheet and recognized in revenue when the hedged crude oil and
natural gas are sold. There were no such deferred gains or losses at
June 30, 2000 or December 31, 1999. Gains or losses on derivative
financial instruments that do not qualify as a hedge are recognized in
income currently.
As a result of hedging transactions, oil and gas revenues were reduced
by $24.8 million and $9.0 million in the second quarter of 2000 and
1999, respectively. For the first six months of 2000 and 1999, oil and
gas revenues were reduced by $51.3 million and $8.8 million,
respectively, as a result of hedging transactions. On February 26,
1999, the Company entered into a swap arrangement with a major
financial institution that effectively converts the interest rate on
$16.4 million notional amount of the 9-1/2% Senior Subordinated Notes
due 2008 ("Notes") to a variable LIBOR-based rate. On February 25,
2000, this arrangement was extended through February 26, 2001. Amounts
paid to enter into these arrangements were insignificant. Based on
LIBOR rates in effect at June 30, 2000, this amounted to a net
reduction in the carrying cost of the Notes from
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NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
9-1/2% to 7.03%, or 247 basis points. In addition, the swap
arrangement also effectively sets the price at which the Company can
repurchase these Notes. For the three and six months ended June 30,
2000, the Company recorded an unrealized gain of $410,000 and an
unrealized loss of $371,000, respectively, related to the change in the
fair value of the Notes. This agreement has an early termination clause
at the discretion of the Company. In July 2000, a portion of this swap
arrangement was settled on a notional amount of $5.0 million of the
Notes. The Company will record a gain of approximately $100,000 as a
result of this settlement.
For 2000, the Company entered into swap contracts on 16,500 barrels of
oil per day ("BOPD"), at an average West Texas Intermediate ("WTI")
price of $17.94 per barrel. The Company also entered into collars on an
additional 16,500 BOPD, with a floor of $16.00 per barrel and ceiling
of $21.21 per barrel. This production is hedged based on a fixed NYMEX
price. In May 2000, in connection with the sale of certain non-core
California oil and gas properties (see Note 9), the Company unwound the
$21.21 per barrel ceiling on 2,800 BOPD for the period May 2000 through
December 2000. The settlement loss of approximately $3.0 million
related to the unwinding of the ceiling was recognized as an adjustment
to the gain on the sale of the non-core California oil and gas
properties, for which the ceiling was designated as a hedge of
production. The Company re-designated the remaining floors of 2,800
BOPD for the period May 2000 through December 2000, as a hedge of other
California production. Also for the year 2000, the Company has entered
into basis swaps on 3,000 BOPD of its production in the Congo, hedging
the basis differential between No. 6 fuel oil and WTI at an average
differential of $1.88 per barrel. At June 30, 2000, the market value of
the hedge positions was a loss of approximately $50.1 million.
For 2001, the Company has entered into swap arrangements on 26,000 BOPD
for the first quarter at an average WTI price of $19.52 per barrel, for
the second quarter on 25,000 BOPD at an average WTI price of $19.54 per
barrel, for the third quarter on 20,000 BOPD at an average WTI price of
$21.22 per barrel, and for the fourth quarter on 15,500 BOPD at an
average WTI price of $22.95 per barrel. At June 30, 2000, the market
value of these swaps was a loss of $40.7 million. These agreements
expose the Company to counterparty credit risk to the extent that the
counterparty is unable to meet its settlement commitments to the
Company.
RECENT ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities". This statement, as amended by SFAS No. 137 and SFAS No.
138, establishes standards of accounting for and disclosures of
derivative instruments and hedging activities. This statement requires
all derivative instruments to be carried on the balance sheet at fair
value and is effective for the Company beginning January 1, 2001. The
Company has not yet determined the impact of this statement on its
financial condition or results of operations.
RECLASSIFICATIONS
Certain reclassifications of prior year amounts have been made to
conform to the current presentation.
2. PROPERTY AND EQUIPMENT
The Company utilizes the successful efforts method of accounting for
its investments in oil and gas properties. Under successful efforts,
oil and gas lease acquisition costs and intangible drilling costs
associated with exploration efforts that result in the discovery of
proved reserves and costs associated with development drilling, whether
or not successful, are capitalized when incurred. When a proved
property is sold, ceases to produce or is abandoned, a gain or loss is
recognized. When an entire interest in an unproved property is sold for
cash or cash equivalent, gain or loss is recognized, taking into
consideration any recorded impairment. When a partial interest in an
unproved property is sold, the amount received is treated as a
reduction of the cost of the interest retained.
Unproved leasehold costs are capitalized pending the results of
exploration efforts. Significant unproved leasehold costs are reviewed
periodically and a loss is recognized to the extent, if any, that the
cost of the
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NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
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 productive wells, development dry holes and productive leases
are capitalized and depleted on a unit-of-production basis over the
life of the remaining proved reserves. Capitalized drilling costs are
depleted on a unit-of-production basis over the life of the remaining
proved developed reserves. Estimated costs (net of salvage value) of
dismantlement, abandonment and site remediation are computed by the
Company's independent reserve engineers and are included when
calculating depreciation and depletion using the unit-of-production
method.
The Company reviews proved oil and gas properties on a depletable unit
basis whenever events or circumstances indicate that the carrying value
of those assets may not be recoverable. For each depletable unit
determined to be impaired, an impairment loss equal to the difference
between the carrying value and the fair value of the depletable unit is
recognized. Fair value, on a depletable unit basis, is estimated to be
the value of the undiscounted expected future net revenues computed by
application of estimated future oil and gas prices, production and
expenses, as determined by management, to estimated future production
of oil and gas reserves over the economic life of the reserves. If the
carrying value exceeds the undiscounted future net revenues, an
impairment is recognized equal to the difference between the carrying
value and the discounted estimated future net revenues of that
depletable unit. The Company considers all proved reserves and
commodity pricing based on available market information in its estimate
of future net revenues.
3. DEFERRED TAX ASSETS
The Company has deferred tax assets, net of valuation allowances, of
$23.0 million and $24.0 million as of June 30, 2000 and December 31,
1999, respectively. The Company believes that sufficient future taxable
income will be generated and has concluded that these net deferred tax
assets will more likely than not be realized.
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NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
4. INDUSTRY SEGMENT INFORMATION
As of June 30, 2000, the Company's oil and gas exploration and
production operations were concentrated primarily in two geographic
regions: domestically, onshore and offshore California, and
internationally, offshore the Republic of Congo in West Africa (the
"Congo").
For the Six Months Ended June 30,
---------------------------------
2000 1999
-------- --------
(amounts in thousands)
Sales to unaffiliated customers:
Oil and gas - Domestic................................... $ 121,354 $ 85,425
Oil and gas - International.............................. 21,974 10,915
-------------- --------------
Total sales................................................... 143,328 96,340
Gain on sale of assets, net.............................. 506 80,312
Other revenues........................................... 821 2,851
-------------- --------------
Total revenues................................................ $ 144,655 $ 179,503
============== ==============
Operating profit before income taxes:
Oil and gas - Domestic (a)............................... $ 35,399 $ 61,516
Oil and gas - International.............................. 7,219 (806)
-------------- --------------
42,618 60,710
Unallocated corporate expenses................................ 19,995 14,699
Interest expense.............................................. 16,807 16,400
Dividends on TECONS........................................... 3,306 3,306
-------------- --------------
Income before income taxes............................... $ 2,510 $ 26,305
============== ==============
Depreciation, depletion and amortization:
Oil and gas - Domestic................................... $ 26,854 $ 41,651
Oil and gas - International.............................. 4,236 3,855
Other.................................................... 733 751
-------------- --------------
$ 31,823 $ 46,257
============== ==============
(a) Includes an $80.3 million gain on sale of the East Texas gas properties
for the six months ended June 30, 1999.
5. LONG-TERM DEBT
Long-term debt consists of the following (amounts in thousands):
June 30, December 31,
2000 1999
------------ ------------
9 1/2% Senior Subordinated Notes due 2008............................ $ 257,310 $ 257,310
9 1/2% Senior Subordinated Notes due 2006............................ 2,417 2,440
Bank credit facility (a)............................................. 103,500 81,000
OPIC credit facility................................................. -- 750
------------ ------------
Total debt..................................................... 363,227 341,500
Less: current maturities............................................. -- (750)
------------ ------------
Long-term debt....................................................... $ 363,227 $ 340,750
============ ============
(a) Nuevo's Third Restated Credit Agreement dated June 7, 2000, provides
for secured revolving credit availability of up to $410.0 million
(subject to a semi-annual borrowing base determination) from a bank
group led by Bank of America, N.A., Bank One, NA, and Bank of Montreal,
until its expiration on June 7,
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NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
2005. The borrowing base on the Company's credit facility is subject to
a semi-annual borrowing base determination on March 1 and September 1
of each year, beginning September 1, 2000. The borrowing base at June
30, 2000, was $300.0 million. The Company was in compliance with all
covenants as of June 30, 2000, and does not anticipate any issues of
non-compliance arising in the foreseeable future. At June 30, 2000,
outstanding borrowings under the revolving credit agreement and an
uncommitted line of credit were $103.5 million. Accordingly, $196.5
million of credit capacity was unused and available at June 30, 2000.
6. EARNINGS PER SHARE COMPUTATION
SFAS No. 128 requires a reconciliation of the numerator (income) and
denominator (shares) of the basic earnings per share ("EPS")
computation to the numerator and denominator of the diluted EPS
computation. In the three-month period ended June 30, 1999, there were
no potential dilutive common shares. The Company's reconciliation is as
follows (amounts in thousands):
For the Three Months Ended June 30,
----------------------------------------------------
2000 1999
-------------------------- ------------------------
Income Shares Loss Shares
------------ ------------ ----------- -----------
Earnings per Common share - Basic.................. $ 854 17,587 $ (15,558) 19,853
Effect of dilutive securities:
Stock options...................................... --- 352 --- ---
------------ ------------ ----------- -----------
Earnings per Common share - Diluted................ $ 854 17,939 $ (15,558) 19,853
============ ============ =========== ===========
For the Six Months Ended June 30,
----------------------------------------------------
2000 1999
-------------------------- ------------------------
Income Shares Loss Shares
------------ ------------ ----------- -----------
Earnings per Common share - Basic.................. $ 1,499 17,701 $ 15,784 19,848
Effect of dilutive securities:
Stock options...................................... --- 373 --- 67
------------ ------------ ----------- -----------
Earnings per Common share - Diluted................ $ 1,499 18,074 $ 15,784 19,915
============ ============ =========== ===========
7. CONTINGENCIES AND OTHER MATTERS
The Company had been named as a defendant in Gloria Garcia Lopez and
Husband, Hector S. Lopez, Individually, and as successors to Galo Land
& Cattle Company v. Mobil Producing Texas & New Mexico, et al. in the
79th Judicial District Court of Brooks County, Texas. On June 9, 2000,
the parties entered into a memorandum of settlement agreement, pursuant
to which the lawsuit would be dismissed (subject to and upon execution
of final settlement documents), the defendants would pay the plaintiffs
$12.0 million and the lease agreement would be amended. Nuevo's working
interest in these properties is 20%, and its share of the settlement
payment is approximately $2.4 million.
The Company has been named as a defendant in certain other lawsuits
incidental to its business. Management does not believe that the
outcome of such litigation will have a material adverse impact on the
Company's operating results or financial condition. However, these
actions and claims in the aggregate seek substantial damages against
the Company and are subject to the inherent uncertainties present in
any litigation. The Company is defending itself vigorously in all such
matters.
In March 1999, the Company 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. The Company has reviewed and,
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NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
where appropriate, strengthened its internal control procedures. As a
result of ongoing negotiations, the Company is confident that it will
recoup a portion of the loss.
In September 1997, there was a spill of crude oil into the Santa
Barbara Channel from a pipeline that connects the Company's Point
Pedernales field with shore-based processing facilities. The volume of
the spill was estimated to be 163 barrels of oil. The costs of the
clean up and the cost to repair the pipeline either have been or are
expected to be covered by insurance, less the Company's deductibles,
which in total are $120,000. Repairs were completed by the end of 1997,
and production recommenced in December 1997. The Company also has
exposure to costs that may not be recoverable from insurance, including
certain fines, penalties, and damages. Such costs are not quantifiable
at this time, but are not expected to be material to the Company's
operating results, financial condition or liquidity.
The Company's international investments involve risks typically
associated with investments in emerging markets such as an uncertain
political, economic, legal and tax environment and expropriation and
nationalization of assets. In addition, if a dispute arises in its
foreign operations, the Company may be subject to the exclusive
jurisdiction of foreign courts or may not be successful in subjecting
foreign persons to the jurisdiction of the United States. The Company
attempts to conduct its business and financial affairs so as to protect
against political and economic risks applicable to operations in the
various countries where it operates, but there can be no assurance that
the Company will be successful in so protecting itself. A portion of
the Company's investment in the Republic of Congo in West Africa
("Congo") is insured through political risk insurance provided by the
Overseas Private Investment Corporation ("OPIC"). The political risk
insurance through OPIC covers up to $25.0 million relating to
expropriation and political violence, which is the maximum coverage
available through OPIC. The Company has no deductible for this
insurance. The Company will consider its options for political risk
insurance in the Republic of Ghana in West Africa ("Ghana") as it
evaluates business opportunities.
In connection with their respective February 1995 acquisitions of two
subsidiaries owning interests in the Yombo field offshore West Africa
(each a "Congo subsidiary"), the Company and a wholly-owned subsidiary
of CMS NOMECO Oil & Gas Co. ("CMS") agreed with the seller not to claim
certain tax losses incurred by such subsidiaries prior to the
acquisitions. Under the tax law in the Congo, as it existed when this
acquisition took place, if an entity is acquired in its entirety and
that entity has certain tax attributes, for example tax loss
carryforwards from operations in the Republic of Congo, the subsequent
owners of that entity can continue to utilize those losses without
restriction. Pursuant to the agreement, the Company and CMS may be
liable to the seller for the recapture of these tax losses utilized by
the seller in years prior to the acquisitions if certain triggering
events occur. A triggering event will not occur if a subsequent
purchaser enters into certain agreements specified in the consolidated
return regulations intended to ensure that such losses will not be
claimed. The only time limit associated with the occurrence of a
triggering event relates to the utilization of a dual consolidated loss
in a foreign jurisdiction. A dual consolidated loss that is utilized to
offset income in a foreign jurisdiction is only subject to recapture
for 15 years following the year in which the dual consolidated loss was
incurred for US income tax purposes. The Company's potential direct
liability could be as much as $48.5 million if a triggering event with
respect to the Company occurs. Additionally, the Company believes that
CMS's liability (for which the Company would be jointly liable with an
indemnification right against CMS) could be as much as $64.1 million.
The Company does not expect a triggering event to occur with respect to
it or CMS and does not believe the agreement will have a material
adverse effect upon the Company.
8. CONTINGENT PAYMENT AND PRICE SHARING AGREEMENTS
In connection with the acquisition from Unocal in 1996 of the
properties located in California, the Company is 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
12
13
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
per Bbl. under the agreement (determined based on near month of
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).
The Company accumulates credits to offset the contingent payment when
prices are $.50 per Bbl. or more below the minimum price. The Company
computes this calculation annually and had accumulated $30.8 million in
price credits as of December 31, 1999, which will be used to reduce
future amounts owed under the contingent payment. The Company expects
that it will still have an accumulated credit balance at the end of
2000 to offset future payments under this agreement. A continuation of
higher than normal oil price realizations would, however, trigger
payments under this agreement beginning in March of 2002.
In connection with the acquisition of the Congo properties in 1995, the
Company entered into a price sharing agreement with the seller. 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, then the Company is 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 for 2000 is $15.19 per Bbl. The benchmark price
increases each year based on the increase in the Consumer Price Index.
For 2000, the effect of this agreement is that Nuevo is entitled to
receive the pricing upside above $15.19 per Bbl. on approximately 56%
of its Congo production.
The Company acquired a 12% working interest in the Point Pedernales oil
field from Unocal in 1994 and the remainder of its interest in this
field from Torch Energy Advisors Inc. ("Torch") in 1996. The Company is
entitled to all revenue proceeds up to $9.00 per Bbl., with the excess
over $9.00 per Bbl., if any, shared among the Company and the original
owners from whom Torch acquired its interest. For 2000, the effect of
this agreement is that Nuevo is entitled to receive the pricing upside
above $9.00 per Bbl. on approximately 34% of its net Point Pedernales
production.
9. DIVESTITURES
In May 2000, the Company sold its working interest in the Las Cienegas
field in California for proceeds of approximately $4.6 million. The
Company reclassified these assets to assets held for sale during the
third quarter of 1999, at which time it discontinued depleting and
depreciating these assets. No impairment charge was recorded upon
reclassification to assets held for sale. In connection with this sale,
the Company unwound hedges of 2,800 BOPD for the period May 2000
through December 2000 (see Note 1) and recorded a net gain on sale of
approximately $740,000.
10. SHARE REPURCHASES
In August 1999, the Company implemented a share repurchase program,
pursuant to the Board of Directors' authorizations to repurchase up to
a total of 3,616,600 shares at times and at prices deemed attractive by
management. As of June 30, 2000, the Company had repurchased 2,660,600
shares of its common stock in open market transactions at an average
purchase price, including commissions, of $16.79 per share.
13
14
NUEVO ENERGY COMPANY
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
FORWARD LOOKING STATEMENTS
This document includes "forward looking statements" within the meaning
of Section 27A of the Securities Act of 1933, as amended (the
"Securities Act"), and Section 21E of the Securities Exchange Act of
1934 ("Exchange Act"). All statements other than statements of
historical facts included in this document, including without
limitation, statements under "Management's Discussion and Analysis of
Financial Condition and Results of Operations" regarding the Company's
financial position, estimated quantities and net present values of
reserves, business strategy, plans and objectives of management of the
Company for future operations and covenant compliance, are
forward-looking statements. Although the Company believes that the
assumptions upon which such forward-looking statements are based are
reasonable, it can give no assurances that such assumptions will prove
to have been correct. Important factors that could cause actual results
to differ materially from the Company's expectations ("Cautionary
Statements") are disclosed below and elsewhere in this document and in
the Company's Annual Report on Form 10-K and other filings made with
the Securities and Exchange Commission. All subsequent written and oral
forward-looking statements attributable to the Company or persons
acting on its behalf are expressly qualified by the Cautionary
Statements.
CAPITAL RESOURCES AND LIQUIDITY
Since inception, the Company has expanded its operations through a
series of disciplined, low-cost acquisitions of oil and gas properties
and the subsequent exploitation and development of these properties.
The Company has complemented these efforts with strategic divestitures
and an opportunistic exploration program, which provides exposure to
prospects that have the potential to add substantially to the growth of
the Company. The funding of these activities has historically been
provided by operating cash flows, bank financing, private and public
placements of debt and equity securities, property divestitures and
joint ventures with industry participants. Net cash provided by (used
in) operating activities was $36.3 million and $(13.2) million for the
six months ended June 30, 2000 and 1999, respectively. The Company
invested $43.6 million and $35.5 million in oil and gas properties for
the six months ended June 30, 2000 and 1999, respectively.
The current borrowing base on the Company's credit facility is $300.0
million. At June 30, 2000, outstanding borrowings under the revolving
credit agreement and an uncommitted line of credit were $103.5 million.
Accordingly, $196.5 million of credit capacity was unused and available
at June 30, 2000. At June 30, 2000, the Company had working capital of
$8.3 million.
On June 7, 2000, the Company entered into its Third Restated Credit
Agreement, which provides for secured revolving credit availability of
up to $410.0 million (subject to a semi-annual borrowing base
determination) 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 on the Company's credit facility is subject to a
semi-annual borrowing base determination on March 1 and September 1 of
each year, beginning September 1, 2000. The borrowing base at June 30,
2000, was $300.0 million. The Company was in compliance with all
covenants as of June 30, 2000, and does not anticipate any issues of
non-compliance arising in the foreseeable future. Subsequent
semi-annual borrowing base redeterminations will require the consent of
banks holding 60% of the total facility commitments, while an increase
in the borrowing base will require the consent of banks holding 66 2/3%
of the total facility commitments.
In July 2000, the Company announced that it no longer expects that its
Brea Highlands residential development will receive entitlement from
the City of Brea, California by the end of 2000. The Company had
planned to sell or joint venture this property upon completion of the
entitlement process. This expected delay results from a political
initiative that, if passed, will subject certain future development
projects, such as Brea Highlands, to a public vote. Because of this
delay, the Company plans to defer $20.0 million of its $140.0 million
2000 capital budget. The revised 2000 capital budget of $120.0 million
is designed to preserve the Company's financial condition and
liquidity.
The Company believes its cash flow from operations and available
financing sources are sufficient to meet its obligations as they become
due and to finance its exploration and development programs.
14
15
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
CAPITAL EXPENDITURES
As mentioned above, the Company plans to defer $20.0 million of its
$140.0 million 2000 capital budget, as a result of expected delays in
the potential sale or joint venture of a real estate development. Under
the revised 2000 capital budget of $120.0 million, the Company
anticipates spending approximately $58.0 million on development
activities and approximately $15.0 million on exploration activities
and business development projects during the remainder of the year.
Exploration and development expenditures, including amounts expensed
under the successful efforts method, for the first six months of 2000
and 1999 are as follows (amounts in thousands):
For the Six Months Ended
June 30,
-------------------------
2000 1999
---------- ----------
Domestic $ 44,063 $ 17,274
International 4,515 19,421
---------- ----------
Total $ 48,578 $ 36,695
========== ==========
The following is a description of significant exploration and
development activity during the first six months of 2000.
Exploration Activity
Domestic
There was no significant activity during the first half of 2000.
International
On February 16 2000, the Company completed its acquisition and
processing of a 3-D seismic survey across the Eastern portion of its
Accra-Keta concession offshore the Republic of Ghana in West Africa
("Ghana"). The Company's costs of the 3-D seismic survey acquisition
and processing were approximately $3.0 million. This survey extends
from the outer shelf, across the slope, and into the deepwater regions
of the block. The Company currently plans to drill its first
exploratory well on the concession late this year. Estimated costs to
drill this well are approximately $12.5 million, on a gross basis.
In June 2000, the Company acquired interests in two exploration permits
in the Republic of Tunisia, North Africa, that add 1.3 million acres to
the Company's international portfolio. The first of these permits is
the 171,000-acre Alyane Permit located offshore Tunisia in the Gulf of
Gabes. The Company will own a 100% participating interest and act as
operator of the block.
The Convention and Joint Venture Agreement for the Alyane Permit call
for an initial term of four years, followed by two optional three-year
terms. Nuevo's work commitment requires shooting 3-D seismic and
drilling one exploratory well on the Alyane Permit in the initial term.
The Company's anticipated costs under this commitment are approximately
$9.0 million. The Company plans to explore the Alyane Permit
aggressively and will acquire 3-D seismic data in mid 2001 with the aim
of drilling its first exploratory well in 2002. Nuevo anticipates
formal government approval of the Convention and Joint Venture
Agreement in the first quarter of 2001.
Effective April 1, 2000, Nuevo acquired a 10.42% participating interest
from Bligh Tunisia Inc. in the 1.1-million-acre Anaguid Permit located
onshore southern Tunisia in the Ghadames Basin for approximately $1.5
million. Operated by Anadarko Petroleum Company, this permit is on
trend with Anadarko's prolific Hassi Berkine complex located to the
west in Algeria. Under the current work commitment, the partners must
drill one exploration well on the Anaguid Permit by December 2001. The
Company's anticipated costs under this
15
16
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
commitment are approximately $1.3 million. In addition, the partners will
reprocess all existing seismic data and acquire new 2-D seismic data
during 2000. Following the expiration of the current work commitment term
in December 2001, the final renewal phase requires the drilling of one
exploration well on the Anaguid Permit during the 2 1/2-year term. Nuevo
expects to receive government approval of this acquisition in the first
quarter of 2001.
In addition to acquiring its interests in the Anaguid and Alyane Permits,
Nuevo has, effective April 1, 2000, increased its existing 17.5%
participating interest in the 900,000-acre Fejaj Permit onshore Tunisia
by acquiring an additional 20% participating interest from Bligh Tunisia
Inc. Nuevo and its partners plan to re-enter and deepen the Chott Fejaj
#3 well on the Fejaj Permit to test a sub-salt prospect. The Company's
anticipated costs under this commitment are approximately $750,000. The
current term of the Fejaj Permit expires in April 2001, but a one-year
extension is being sought. The Chott Fejaj #3 well was drilled initially
to the top of salt in 1998.
Development Activity
Domestic
The Company drilled a total of 103 development wells in the first half of
2000, most of which relate to the interests acquired from Texaco in 1999.
The Company completed the first phase of its development-drilling program
on its Cymric lease acquired from Texaco, which included drilling 40
wells. The Company began the second phase of this development program in
June 2000, which includes drilling an additional 60 wells. The Company
expects this program to be completed by the end of first quarter 2001.
The wells drilled to date are currently producing at a combined rate of
3,000 barrels of oil per day ("BOPD"). In total, the Company drilled 54
wells on its Cymric lease (four of which were horizontal wells), 17 wells
on its Belridge lease (seven of which were horizontal wells), and 29
wells at Midway Sunset. Additionally, 49 injectors have been drilled to
support the production from these fields. In addition to the development
activity at Cymric, the Company successfully drilled two offshore wells
at its Huntington Beach property. These two wells have been completed and
are producing 350 BOPD.
A significant facility expansion is underway at the Brea Olinda field.
The Company had flared approximately 2.5 MMCF of natural gas per day, due
to the lack of a gas market. In the second quarter of 2000, the Company
completed the installation of its first self-generation unit, which
utilizes the gas and converts it to electricity to supply all of the
field electrical needs as well as provides excess electricity for sale.
The completion of the self-generation project cost approximately $4.5
million and should result in significant cost savings of approximately
$450,000 per year plus an additional $1.7 million per year in electricity
sales for the Brea Olinda property. A second unit should be installed and
online by year-end 2000. Also, the Company is currently constructing a
water plant at its Cymric Field that will provide a long-term source of
water to be used in the Company's steam operations and help reduce
expenses in the long-term. The water plant is expected to cost
approximately $6.2 million to construct.
International
There was no significant activity during the first half of 2000.
DERIVATIVE FINANCIAL INSTRUMENTS
The Company utilizes derivative financial instruments to reduce its
exposure to decreases in the market prices of crude oil and natural gas.
Commodity derivatives utilized as hedges include futures, swap and option
contracts, which are used to hedge crude oil and natural gas prices.
Basis swaps are sometimes used to hedge the basis differential between
the derivative financial instrument index price and the commodity field
price. In order to qualify as a hedge, price movements in the underlying
commodity derivative must be highly correlated with the hedged commodity.
Settlement of gains and losses on price swap contracts are realized
monthly, generally based upon the difference between the contract price
and the average closing New York Mercantile Exchange ("NYMEX") price and
are reported as a component of oil and gas revenues and operating cash
flows in the period realized.
16
17
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Gains and losses on option and futures contracts that qualify as a hedge
of firmly committed or anticipated purchases and sales of oil and gas
commodities are deferred on the balance sheet and recognized in income
and operating cash flows when the related hedged transaction occurs.
Premiums paid on option contracts are deferred in other assets and
amortized into oil and gas revenues over the terms of the respective
option contracts. Gains or losses attributable to the termination of a
derivative financial instrument are deferred on the balance sheet and
recognized in revenue when the hedged crude oil and natural gas are sold.
There were no such deferred gains or losses at June 30, 2000 or December
31, 1999. Gains or losses on derivative financial instruments that do not
qualify as a hedge are recognized in income currently.
As a result of hedging transactions, oil and gas revenues were reduced by
$24.8 million and $9.0 million in the second quarter of 2000 and 1999,
respectively. For the first six months of 2000 and 1999, oil and gas
revenues were reduced by $51.3 million and $8.8 million, respectively, as
a result of hedging transactions.
On February 26, 1999, the Company entered into a swap arrangement with a
major financial institution that effectively converts the interest rate
on $16.4 million notional amount of the 9-1/2 % Senior Subordinated Notes
due 2008 ("Notes") to a variable LIBOR-based rate. On February 25, 2000,
this arrangement was extended through February 26, 2001. Amounts paid to
enter into these arrangements were insignificant. Based on LIBOR rates in
effect at June 30, 2000, this amounted to a net reduction in the carrying
cost of the Notes from 9-1/2 % to 7.03%, or 247 basis points. In
addition, the swap arrangement also effectively sets the price at which
the Company can repurchase these Notes. For the three and six months
ended June 30, 2000, the Company recorded an unrealized gain of $410,000
and an unrealized loss of $371,000, respectively, related to the change
in the fair value of the Notes. This agreement has an early termination
clause at the discretion of the Company. In July 2000, a portion of this
swap arrangement was settled on a notional amount of $5.0 million of the
Notes. The Company will record a gain of approximately $100,000 as a
result of this settlement.
For 2000, the Company entered into swap contracts on 16,500 barrels of
oil per day ("BOPD"), at an average West Texas Intermediate ("WTI") price
of $17.94 per barrel. The Company also entered into collars on an
additional 16,500 BOPD, with a floor of $16.00 per barrel and ceiling of
$21.21 per barrel. This production is hedged based on a fixed NYMEX
price. In May 2000, in connection with the sale of certain non-core
California oil and gas properties (see Note 9), the Company unwound the
$21.21 per barrel ceiling on 2,800 BOPD for the period May 2000 through
December 2000. The settlement loss of approximately $3.0 million related
to the unwinding of the ceiling was recognized as an adjustment to the
gain on the sale of the non-core California oil and gas properties, for
which the ceiling was designated as a hedge of production. The Company
re-designated the remaining floors of 2,800 BOPD for the period May 2000
through December 2000, as a hedge of other California production. Also
for the year 2000, the Company has entered into basis swaps on 3,000 BOPD
of its production in the Congo, hedging the basis differential between
No. 6 fuel oil and WTI at an average differential of $1.88 per barrel. At
June 30, 2000, the market value of the hedge positions was a loss of
approximately $50.1 million.
For 2001, the Company has entered into swap arrangements on 26,000 BOPD
for the first quarter at an average WTI price of $19.52 per barrel, for
the second quarter on 25,000 BOPD at an average WTI price of $19.54 per
barrel, for the third quarter on 20,000 BOPD at an average WTI price of
$21.22 per barrel, and for the fourth quarter on 15,500 BOPD at an
average WTI price of $22.95 per barrel. At June 30, 2000, the market
value of these swaps was a loss of $40.7 million. These agreements expose
the Company to counterparty credit risk to the extent that the
counterparty is unable to meet its settlement commitments to the Company.
CONTINGENT PAYMENT AND PRICE SHARING AGREEMENTS
In connection with the acquisition from Unocal in 1996 of the properties
located in California, the Company is 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
17
18
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
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 near month of
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). The
Company accumulates credits to offset the contingent payment when prices
are $.50 per Bbl. or more below the minimum price. The Company computes
this calculation annually and had accumulated $30.8 million in price
credits as of December 31, 1999, which will be used to reduce future
amounts owed under the contingent payment. The Company expects that it
will still have an accumulated credit balance at the end of 2000 to
offset future payments under this agreement. A continuation of higher
than normal oil price realizations would, however, trigger payments under
this agreement beginning in March of 2002.
In connection with the acquisition of the Congo properties in 1995, the
Company entered into a price sharing agreement with the seller. 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, then the Company is 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 for 2000 is $15.19 per Bbl. The benchmark price increases
each year based on the increase in the Consumer Price Index. For 2000,
the effect of this agreement is that Nuevo is entitled to receive the
pricing upside above $15.19 per Bbl. on approximately 56% of its Congo
production.
The Company acquired a 12% working interest in the Point Pedernales oil
field from Unocal in 1994 and the remainder of its interest in this field
from Torch Energy Advisors Inc. ("Torch") in 1996. The Company is
entitled to all revenue proceeds up to $9.00 per Bbl., with the excess
over $9.00 per Bbl., if any, shared among the Company and the original
owners from whom Torch acquired its interest. For 2000, the effect of
this agreement is that Nuevo is entitled to receive the pricing upside
above $9.00 per Bbl. on approximately 34% of its net Point Pedernales
production.
RECENT ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities". This statement, as amended by SFAS No. 137 and SFAS No. 138,
establishes standards of accounting for and disclosures of derivative
instruments and hedging activities. This statement requires all
derivative instruments to be carried on the balance sheet at fair value
and is effective for the Company beginning January 1, 2001. The Company
has not yet determined the impact of this statement on its financial
condition or results of operations.
SHARE REPURCHASES
In August 1999, the Company implemented a share repurchase program,
pursuant to the Board of Directors' authorizations to repurchase up to a
total of 3,616,600 shares at times and at prices deemed attractive by
management. As of June 30, 2000, the Company has repurchased 2,660,600
shares of its common stock in open market transactions at an average
purchase price, including commissions, of $16.79 per share.
DEFERRED INCOME TAXES
The Company has deferred tax assets, net of valuation allowances, of
$23.0 million and $24.0 million as of June 30, 2000 and December 31,
1999, respectively. The Company believes that sufficient future taxable
income will be generated and has concluded that these net deferred tax
assets will more likely than not be realized.
18
19
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
RESULTS OF OPERATIONS (THREE MONTHS ENDED JUNE 30, 2000 AND 1999)
The following table sets forth certain operating information of the
Company (inclusive of the effect of crude oil and natural gas hedging) for the
periods presented:
Three Months
Ended June 30, %
--------------------- Increase/
2000 1999 (Decrease)
------ ------ ----------
PRODUCTION:
Oil and condensate - Domestic (MBBL.S) ................... 3,640 3,831 (5%)
Oil and condensate - International (MBBL.S)............... 477 459 4%
------ ------
Oil and condensate - Total (MBBL.S)....................... 4,117 4,290 (4%)
Natural gas - Domestic (MMCF)............................. 3,816 4,135 (8%)
Natural gas liquids - Domestic (MMCF)..................... 44 50 (12%)
Equivalent barrels of production - Domestic (MBOE)........ 4,320 4,570 (5%)
Equivalent barrels of production - International (MBOE)... 477 459 4%
------ ------
Equivalent barrels of production - Total (MBOE)........... 4,797 5,029 (5%)
AVERAGE SALES PRICE:
Oil and condensate - Domestic............................. $13.12 $ 9.50 38%
Oil and condensate - International........................ $22.63 $15.73 44%
Oil and condensate - Total................................ $14.23 $10.17 40%
Natural gas - Domestic.................................... $ 3.43 $ 1.92 79%
LEASE OPERATING EXPENSE:
Average unit production cost(1) per BOE - Domestic........ $ 7.12 $ 5.90 21%
Average unit production cost(1) per BOE - International... $ 7.37 $ 7.28 1%
Average unit production cost(1) per BOE - Total........... $ 7.14 $ 6.02 19%
(1) Costs incurred to operate and maintain wells and related equipment
and facilities, including ad valorem and severance taxes.
Revenues
Oil and Gas Revenues:
Oil and gas revenues for the three months ended June 30, 2000, were $72.6
million, or 37% higher than oil and gas revenues for the same period in 1999.
This increase is primarily due to a 40% increase in realized oil prices and a
79% increase in realized gas prices. These increases were partially offset by a
decrease in production, which was primarily attributable to asset sales,
production interruptions due to pump replacements and power shortages
(brown-outs) in California during recent periods of extreme temperatures, and
reduced capital spending in 1999. Second quarter 2000 oil price realizations
reflect hedging losses of $24.8 million, or $6.03 per barrel.
Domestic: Oil and gas revenues for the three months ended June 30, 2000, were
35% higher than oil and gas revenues for the same period in 1999. This increase
is primarily due to a 38% improvement in average realized oil prices and a 79%
improvement in average realized gas prices, partially offset by a 5% decrease in
total production. The Company experienced several production interruptions in
the second quarter of 2000 as a result of pump replacements and brown-outs in
California during recent periods of extreme temperatures. The realized oil price
of
19
20
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
$13.12 per barrel for the second quarter of 2000 includes negative hedging
results of $7.01 per barrel of oil, compared to negative hedging results of
$2.51 per barrel of oil for the second quarter of 1999.
International: Oil revenues for the three months ended June 30, 2000, increased
49% as compared to the same period in 1999. This increase resulted from a 44%
increase in oil price realizations to $22.63 per barrel, coupled with a 4%
increase in oil production. The realized oil price for the second quarter of
2000 includes hedging gains of $1.44 per barrel of oil, compared to hedging
gains of $1.39 per barrel in the second quarter of 1999.
Gain on Sale of Assets, net:
The net gain on sale of assets for the three months ended June 30, 2000, was
$366,000, primarily representing a gain on the sale of certain non-core
California properties (see Note 9 to the Notes to Condensed Consolidated
Financial Statements). Gain on sale of assets, net, for the three months ended
June 30, 1999, was $(1.4) million, representing a negative revision for final
accounting adjustments in connection with the Company's sale of its East Texas
natural gas properties in January 1999.
Interest and Other Income:
Interest and other income for the three months ended June 30, 2000, is comprised
of several individually insignificant items. Interest and other income for the
three months ended June 30, 1999, includes $1.1 million associated with interest
earned on an escrow account for the $100.0 million representing a portion of the
proceeds from the sale of the East Texas natural gas properties, as well as
several individually insignificant items.
Expenses
Lease Operating Expenses:
Lease operating expenses for the three months ended June 30, 2000, were $34.3
million, or 13% higher than for the three months ended June 30, 1999. Lease
operating expenses per barrel of oil equivalent ("BOE") were $7.14 in the second
quarter of 2000, compared to $6.02 in the same period in 1999. The increase is
primarily due to a $4.3 million increase in steam costs resulting from higher
natural gas prices, as well as lower production.
Domestic: Lease operating expenses per BOE were $7.12 in the second quarter of
2000, compared to $5.90 in the same period in 1999. Higher steam costs and
decreased production contributed to the higher lease operating expenses per BOE
quarter over quarter.
Exploration Costs:
Exploration costs, including geological and geophysical ("G&G") costs, dry hole
costs, delay rentals and expensed project costs, were $1.5 million and $7.9
million for the three months ended June 30, 2000 and 1999, respectively. For the
three months ended June 30, 2000, exploration costs were comprised of $0.6
million in G&G (primarily for consulting costs and 3-D seismic processing in the
Accra-Keta prospect offshore Ghana), $0.1 million in dry hole costs, $0.2
million in delay rentals, and $0.6 million of other project costs. For the three
months ended June 30, 1999, exploration costs were comprised of $6.5 million of
dry hole costs (for the Cree Fee 1A well on the Midway Peak prospect in
California), $0.7 million in G&G, $0.1 million in delay rentals and $0.6 million
of other project costs.
Depreciation, Depletion and Amortization:
Depreciation, depletion and amortization for the three months ended June 30,
2000, reflects a 32% decrease from the same period in 1999. This decrease was
driven by a lower depletion rate, which primarily resulted from a significant
increase in reserve estimates attributable to higher commodity prices at
year-end 1999 versus year-end 1998.
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NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
General and Administrative Expenses:
General and administrative expenses were $4.1 million and $3.4 million in the
three months ended June 30, 2000 and 1999, respectively. The 22% increase is due
primarily to a $0.9 million increase in bonus accruals, as bonuses were not
projected or accrued in the second quarter of 1999, offset by a $0.4 million
decrease in the fair market value of securities in the Company's deferred
compensation plan. The remaining increase is made up of individually
insignificant items.
Other Expense:
The $2.2 million increase in other expense from the second quarter of 1999 to
the second quarter of 2000 is primarily due to a $2.0 million accrual for a
lawsuit settlement (see Note 7 to the Notes to Condensed Consolidated Financial
Statements) and $0.7 million in costs to evaluate potential business
transactions. This increase was partially offset by a positive mark to market
adjustment of $0.4 million related to the Company's liability management swap
(see Note 1 to the Notes to Condensed Consolidated Financial Statements) in the
second quarter of 2000.
Net Income (Loss)
Net income of $854,000, $0.05 per common share - basic and diluted, was reported
for the three months ended June 30, 2000, as compared to a net loss of $15.6
million, $0.78 per common share - basic and diluted, reported for the same
period in 1999.
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NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
RESULTS OF OPERATIONS (SIX MONTHS ENDED JUNE 30, 2000 AND 1999)
The following table sets forth certain operating information of the Company
(inclusive of the effect of crude oil and natural gas hedging) for the periods
presented:
Six Months
Ended June 30, %
-------------------- Increase/
2000 1999 (Decrease)
------ ------ ----------
PRODUCTION:
Oil and condensate - Domestic (MBBL.S).................... 7,353 7,815 (6%)
Oil and condensate - International (MBBL.S)............... 978 849 15%
------ -------
Oil and condensate - Total (MBBL.S)....................... 8,331 8,664 (4%)
Natural gas - Domestic (MMCF)............................. 7,811 8,227 (5%)
Natural gas liquids - Domestic (MMCF)..................... 85 93 (9%)
Equivalent barrels of production - Domestic (MBOE)........ 8,741 9,279 (6%)
Equivalent barrels of production - International (MBOE)... 978 849 15%
------ -------
Equivalent barrels of production - Total (MBOE)........... 9,719 10,128 (4%)
AVERAGE SALES PRICE:
Oil and condensate - Domestic............................. $13.13 $ 7.29 80%
Oil and condensate - International........................ $22.47 $ 12.86 75%
Oil and condensate - Total................................ $14.22 $ 9.07 57%
Natural gas - Domestic.................................... $ 2.91 $ 1.87 56%
LEASE OPERATING EXPENSE:
Average unit production cost(1) per BOE - Domestic........ $ 6.69 $ 5.81 15%
Average unit production cost(1) per BOE - International... $ 7.02 $ 7.44 (6%)
Average unit production cost(1) per BOE - Total........... $ 6.73 $ 5.95 13%
(1) Costs incurred to operate and maintain wells and related equipment and
facilities, including ad valorem and severance taxes.
Revenues
Oil and Gas Revenues:
Oil and gas revenues for the six months ended June 30, 2000, were $143.3
million, or 49% higher than oil and gas revenues for the same period in 1999.
This increase is primarily due to a 57% increase in realized oil prices and a
56% increase in realized gas prices. These increases were partially offset by a
decrease in production, which was primarily attributable to asset sales,
production interruptions due to pump replacements and brown-outs in California
during recent periods of extreme temperatures, and reduced capital spending in
1999. First half 2000 oil price realizations reflect hedging losses of $51.3
million, or $6.16 per barrel, compared to hedging losses of $8.8 million, or
$1.01 per barrel in the first half of 1999.
Domestic: Oil and gas revenues for the six months ended June 30, 2000, were 42%
higher than oil and gas revenues for the same period in 1999. This increase is
primarily due to an 80% improvement in average realized oil prices and a 56%
improvement in average realized gas prices, partially offset by a 6% decrease in
total production as a result of asset sales, reduced capital spending in 1999
and production interruptions due to pump replacements and brown-outs
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NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
in California during recent periods of extreme temperatures. The realized oil
price of $13.13 per barrel for the first half of 2000 includes negative hedging
results of $53.4 million, or $7.26 per barrel of oil, compared to hedging losses
of $9.6 million, or $1.23 per barrel in the first half of 1999.
International: Oil revenues for the six months ended June 30, 2000, more than
doubled as compared to the same period in 1999. This significant increase
resulted from a 75% increase in oil price realizations to $22.47 per barrel,
coupled with a 15% increase in oil production. The realized oil price for the
first half of 2000 includes hedging gains of $2.08 per barrel of oil, compared
to hedging gains of $0.98 per barrel in the first half of 1999.
Gain on Sale of Assets, net:
Gain on sale of assets for the six months ended June 30, 2000, was $506,000,
primarily representing a gain on the sale of certain non-core California
properties (see Note 9 to the Notes to Condensed Consolidated Financial
Statements). Gain on sale of assets for the six months ended June 30, 1999, was
$80.3 million, resulting from the Company's sale of its East Texas natural gas
properties in January 1999.
Interest and Other Income:
Interest and other income for the six months ended June 30, 2000, is comprised
of several individually insignificant items. Interest and other income for the
six months ended June 30, 1999, includes $2.4 million associated with interest
earned on an escrow account for the $100.0 million representing a portion of the
proceeds from the sale of the East Texas natural gas properties, as well as
several individually insignificant items.
Expenses
Lease Operating Expenses:
Lease operating expenses for the six months ended June 30, 2000, were $65.4
million, or 9% higher than for the six months ended June 30, 1999. This increase
is primarily due to a $7.0 million increase in steam costs resulting from higher
natural gas prices, partially offset by a decrease in other field costs. Lease
operating expenses per BOE were $6.73 in the first half of 2000, compared to
$5.95 in the same period in 1999. The per barrel increase is primarily due to a
$0.66 per BOE increase in steam costs, as well as the 4% decrease in total
production.
Domestic: Lease operating expenses per BOE were $6.69 in the first half of 2000,
compared to $5.81 in the same period in 1999. Higher steam costs accounted for
$0.85 of the per BOE increase, year over year. The remaining increase is
attributable to the 4% decrease in production.
International: Lease operating expenses per BOE were $7.02 in the first half of
2000, compared to $7.44 in the same period in 1999. The decrease in lease
operating expenses per BOE is primarily attributable to the 15% increase in
production.
Exploration Costs:
Exploration costs, including G&G costs, dry hole costs, delay rentals and
expensed project costs, were $4.7 million and $10.0 million for the six months
ended June 30, 2000 and 1999, respectively. For the six months ended June 30,
2000, exploration costs were comprised of $3.8 million in G&G (primarily for 3-D
seismic acquisition and processing in the Accra-Keta prospect offshore Ghana),
$0.1 million in dry hole costs, $0.2 million in delay rentals, and $0.6 million
of other project costs. For the six months ended June 30, 1999, exploration
costs were comprised of $7.3 million of dry hole costs (for the Cree Fee 1A well
on the Midway Peak prospect in California), $1.5 million in G&G, $0.3 million in
delay rentals and $0.9 million of other project costs.
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NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Depreciation, Depletion and Amortization:
Depreciation, depletion and amortization for the six months ended June 30, 2000,
reflects a 31% decrease from the same period in 1999. This decrease was driven
by a lower depletion rate, which primarily resulted from a significant increase
in reserve estimates attributable to higher commodity prices at year-end 1999
versus year-end 1998.
General and Administrative Expenses:
General and administrative expenses were $9.5 million and $7.2 million for the
six months ended June 30, 2000 and 1999, respectively. The 32% increase is due
primarily to a $1.6 million increase in bonus accruals, as bonuses were not
projected or accrued in the first half of 1999. The remaining increase is made
up of individually insignificant items.
Interest Expense:
Interest expense of $16.8 million for the six months ended June 30, 2000,
increased only slightly as compared to interest expense in the same period in
1999. The increase is primarily attributable to higher interest rates as the
Company exchanged its 8 7/8% Senior Subordinated Notes for 9 1/2% Senior
Subordinated Notes due 2008 in the third quarter of 1999.
Other Expense:
The 29% increase in other expense from the first half of 1999 to the first half
of 2000 is primarily due to a $2.0 million accrual for a lawsuit settlement (see
Note 7 to the Notes to Condensed Consolidated Financial Statements) and $0.7
million in costs to evaluate potential business transactions. This increase also
includes a negative mark to market adjustment of $0.4 million related to the
Company's liability management swap (see Note 1 to the Notes to Condensed
Consolidated Financial Statements) in the first half of 2000. Offsetting this
increase, in March 1999, the Company discovered that a non-officer employee had
fraudulently authorized and diverted for personal use Company funds totaling
$5.9 million, $4.3 million in 1998 and the remainder in the first quarter of
1999, that were intended for international exploration.
Net Income
Net income of $1.5 million, $0.08 per common share - basic and diluted, was
reported for the six months ended June 30, 2000, as compared to net income of
$15.8 million, $0.80 per common share - basic and $0.79 per common share -
diluted, reported for the same period in 1999.
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NUEVO ENERGY COMPANY
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information contained in Item 3 updates, and should be read in conjunction
with, information set forth in Part II, Item 7a in Nuevo's Annual Report on Form
10-K for the year ended December 31, 1999, in addition to the interim condensed
consolidated financial statements and accompanying notes presented in Items 1
and 2 of this Form 10-Q.
There are no material changes in market risks faced by the Company from those
reported in Nuevo's Annual Report on Form 10-K for the year ended December 31,
1999.
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NUEVO ENERGY COMPANY
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Note 7 to the Notes to Condensed Consolidated Financial Statements.
On April 5, 2000, the Company filed a lawsuit against ExxonMobil
Corporation in the United States District Court for the Central District
of California, Western Division. The Company and ExxonMobil each own a
50% interest in the Sacate Field, offshore Santa Barbara County,
California, which can only be accessed from an existing ExxonMobil
platform. The Company has alleged that by grossly inflating the fee that
ExxonMobil insists the Company must pay to use an existing ExxonMobil
platform and production infrastructure, ExxonMobil failed to submit a
proposal for the development of the Sacate field consistent with the Unit
Operating Agreement. The Company therefore believes that it has been
denied a reasonable opportunity to exercise its rights under the Unit
Operating Agreement. ExxonMobil contends that Nuevo had not consented to
the operation and therefore cannot receive its share of production from
Sacate until ExxonMobil has first recovered certain costs and fees. As a
result, Nuevo has neither received revenues nor incurred operating
expenses related to Sacate. The Company has alleged that ExxonMobil's
actions breach the Unit Operating Agreement and the covenant of good
faith and fair dealing. The Company is seeking damages and a declaratory
judgment as to the payment that must be made to access ExxonMobil's
platform and facilities. The Company's capitalized costs associated with
Sacate are insignificant.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At the annual meeting of the stockholders of the Company on May 24, 2000
the following matters were voted on with the following results:
(1) Isaac Arnold, Jr. was elected as a director of the Company with a
total of 14,443,384 shares voting in favor and 492,778 shares
withheld authority.
(2) Thomas D. Barrow was elected as a director of the Company with a
total of 14,923,896 shares voting in favor and 12,266 shares
withheld authority.
(3) David H. Batchelder was elected as a director of the Company with
a total of 14,924,625 shares voting in favor and 11,537 shares
withheld authority.
(4) Charles M. Elson was elected as a director of the Company with a
total of 14,923,743 shares voting in favor and 12,419 shares
withheld authority.
(5) Douglas L. Foshee was elected as a director of the Company with a
total of 14,923,941 shares voting in favor and 12,221 shares
withheld authority.
(6) Robert L. Gerry, III was elected as a director of the Company with
a total of 14,924,139 shares voting in favor and 12,023 shares
withheld authority.
(7) Gary R. Petersen was elected as a director of the Company with a
total of 14,924,139 shares voting in favor and 12,023 shares
withheld authority.
(8) David Ross, III was elected as a director of the Company with a
total of 14,924,625 shares voting in favor and 11,537 shares
withheld authority.
(9) Robert W. Shower was elected as a director of the Company with a
total of 14,924,625 shares voting in favor and 11,537 shares
withheld authority.
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(10) The stockholders approved a proposal to ratify the selection of
KPMG LLP as the Company's independent auditors for the year ending
December 31, 2000, with a total of 14,914,285 shares voting in
favor, a total of 5,121 shares voting against and a total of
16,756 shares abstaining.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) EXHIBITS
10. Material Contracts
10.1 Third Restated Credit Agreement dated June 7, 2000, between
Nuevo Energy Company (Borrower) and Bank of America N.A.
(Administrative Agent), Bank One, NA (Syndication Agent),
Bank of Montreal (Documentation Agent) and certain lenders.
27. Financial Data Schedule
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GLOSSARY OF OIL AND GAS TERMS
TERMS USED TO DESCRIBE QUANTITIES OF OIL AND NATURAL GAS
o Bbl -- One stock tank barrel, or 42 US gallons liquid volume, of
crude oil or other liquid hydrocarbons.
o Bcf -- One billion cubic feet of natural gas.
o Bcfe -- One billion cubic feet of natural gas equivalent.
o BOE -- One barrel of oil equivalent, converting gas to oil at the
ratio of 6 Mcf of gas to 1 Bbl of oil.
o MBbl -- One thousand Bbls.
o Mcf -- One thousand cubic feet of natural gas.
o MMBbl -- One million Bbls of oil or other liquid hydrocarbons.
o MMcf -- One million cubic feet of natural gas.
o MBOE -- One thousand BOE.
o MMBOE -- One million BOE.
TERMS USED TO CLASSIFY OUR RESERVE QUANTITIES
o Proved reserves -- The estimated quantities of crude oil,
natural gas and natural gas liquids which, upon analysis of
geological and engineering data, appear with reasonable certainty
to be recoverable in the future from known oil and natural gas
reservoirs under existing economic and operating conditions.
The SEC definition of proved oil and gas reserves, per Article 4-10(a)(2)
of Regulation S-X, is as follows:
Proved oil and gas reserves. Proved oil and gas reserves are the
estimated quantities of crude oil, natural gas, and natural gas liquids
which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under
existing economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
(a) Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The
area of a reservoir considered proved includes (A) that portion
delineated by drilling and defined by gas-oil and/or oil-water contacts,
if any; and (B) the immediately adjoining portions not yet drilled, but
which can be reasonably judged as economically productive on the basis of
available geological and engineering data. In the absence of information
on fluid contacts, the lowest known structural occurrence of hydrocarbons
controls the lower proved limit of the reservoir.
(b) Reserves which can be produced economically through
application of improved recovery, techniques (such as fluid injection)
are included in the "proved" classification when successful testing by a
pilot project, or the operation of an installed program in the reservoir,
provides support for the engineering analysis on which the project or
program was based.
(c) Estimates of proved reserves do not include the following: (1)
oil that may become available from known reservoirs but is classified
separately as "indicated additional reserves"; (2) crude oil, natural
gas, and natural gas liquids, the recovery of which is subject to
reasonable doubt because of uncertainty as to geology, reservoir
characteristics, or economic factors; (3) crude oil, natural gas, and
natural gas liquids, that may occur in undrilled prospects; and (4) crude
oil, natural gas, and natural gas liquids, that may be recovered from oil
shales, coal,
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gilsonite and other such sources.
o Proved developed reserves -- Proved reserves that can be
expected to be recovered through existing wells with existing
equipment and operating methods.
o Proved undeveloped reserves -- Proved reserves that are expected
to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required.
TERMS USED TO DESCRIBE THE LEGAL OWNERSHIP OF THE COMPANY'S OIL AND GAS
PROPERTIES
o Royalty interest -- A real property interest entitling the owner
to receive a specified portion of the gross proceeds of the sale
of oil and natural gas production or, if the conveyance creating
the interest provides, a specific portion of oil and natural gas
produced, without any deduction for the costs to explore for,
develop or produce the oil and natural gas. A royalty interest
owner has no right to consent to or approve the operation and
development of the property, while the owners of the working
interests have the exclusive right to exploit the mineral on the
land.
o Working interest -- A real property interest entitling the owner
to receive a specified percentage of the proceeds of the sale of
oil and natural gas production or a percentage of the production,
but requiring the owner of the working interest to bear the cost
to explore for, develop and produce such oil and natural gas. A
working interest owner who owns a portion of the working interest
may participate either as operator or by voting his percentage
interest to approve or disapprove the appointment of an operator
and drilling and other major activities in connection with the
development and operation of a property.
TERMS USED TO DESCRIBE SEISMIC OPERATIONS
o 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.
o 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.
o 3-D seismic -- 3-D seismic data is collected using a grid of
energy sources, which are generally spread over several miles. A
3-D survey produces a three dimensional image of the subsurface
geology by collecting seismic data along parallel lines and
creating a cube of information that can be divided into various
planes, thus improving visualization. Consequently, 3-D seismic
data is a more reliable indicator of potential oil and natural gas
reservoirs in the area evaluated.
THE COMPANY'S MISCELLANEOUS DEFINITIONS
o 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.
o 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.
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NUEVO ENERGY COMPANY
PART II. OTHER INFORMATION (CONTINUED)
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
NUEVO ENERGY COMPANY
(Registrant)
Date: August 14, 2000 By:/s/ Douglas L. Foshee
--------------- ----------------------------
Douglas L. Foshee
Chairman, President and Chief
Executive Officer
Date: August 14, 2000 By:/s/ Robert M. King
--------------- -----------------------------
Robert M. King
Senior Vice President and Chief
Financial Officer
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