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 SEPTEMBER 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 November 9, 2000, the number of outstanding shares of the Registrant's
common stock was 17,611,729.
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NUEVO ENERGY COMPANY
INDEX
PAGE
NUMBER
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
Condensed Consolidated Balance Sheets:
September 30, 2000 (Unaudited) and December 31, 1999............................ 3
Condensed Consolidated Statements of Operations (Unaudited):
Three and nine months ended September 30, 2000 and September 30, 1999........... 4
Condensed Consolidated Statements of Cash Flows (Unaudited):
Nine months ended September 30, 2000 and September 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............ 15
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk....................................... 27
PART II. OTHER INFORMATION................................................................................ 28
2
3
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Amounts in Thousands, Except Share Data)
September 30, 2000 December 31, 1999
------------------ -----------------
ASSETS (Unaudited)
CURRENT ASSETS:
Cash and cash equivalents..................................... $ 51,275 $ 10,288
Accounts receivable........................................... 55,775 45,004
Product inventory............................................. 602 4,610
Prepaid expenses and other.................................... 3,618 6,389
--------------- --------------
Total current assets........................................ 111,270 66,291
--------------- --------------
PROPERTY AND EQUIPMENT, AT COST:
Land.......................................................... 51,017 51,017
Oil and gas properties (successful efforts method)............ 1,076,269 1,002,779
Gas plant facilities.......................................... 12,020 12,140
Other facilities.............................................. 14,259 11,874
--------------- --------------
1,153,565 1,077,810
Accumulated depreciation, depletion and amortization.......... (478,949) (429,349)
--------------- --------------
674,616 648,461
--------------- --------------
DEFERRED TAX ASSETS, NET....................................... 17,882 24,005
OTHER ASSETS................................................... 27,152 21,273
--------------- --------------
$ 830,920 $ 760,030
=============== ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable ........................................... $ 22,176 $ 20,492
Accrued interest............................................ 8,410 2,353
Accrued liabilities......................................... 34,132 37,755
Current maturities of long-term debt........................ --- 750
--------------- --------------
Total current liabilities................................ 64,718 61,350
--------------- --------------
LONG-TERM DEBT, NET OF CURRENT MATURITIES...................... 409,727 340,750
OTHER LONG-TERM LIABILITIES.................................... 8,424 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,
20,599,322 and 20,437,371 shares issued and 17,431,844 and
17,931,393 shares outstanding at September 30, 2000 and
December 31, 1999, respectively........................... 206 204
Additional paid-in capital................................. 360,747 357,855
Treasury stock, at cost, 2,999,650 and 2,430,074 shares, at
September 30, 2000 and December 31, 1999, respectively... (61,818) (49,605)
Stock held by benefit trust, 167,828 and 75,904 shares, at
September 30, 2000 and December 31, 1999, respectively... (3,512) (3,184)
Deferred stock compensation................................ (191) (216)
Accumulated deficit........................................ (62,381) (71,416)
--------------- --------------
Total stockholders' equity ............................. 233,051 233,638
--------------- --------------
$ 830,920 $ 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 September 30,
--------------------------------
2000 1999
---------- ----------
REVENUES:
Oil and gas revenues........................................... $ 87,328 $ 68,987
Gain on sale of assets, net.................................... -- (309)
Interest and other income...................................... 2,264 1,570
-------------- --------------
89,592 70,248
-------------- --------------
COSTS AND EXPENSES:
Lease operating expenses....................................... 38,226 35,629
Exploration costs.............................................. 791 620
Depreciation, depletion and amortization....................... 18,062 17,299
Loss on sale of assets, net.................................... 520 --
General and administrative expenses............................ 3,918 4,636
Outsourcing fees............................................... 3,436 3,603
Interest expense............................................... 9,789 7,948
Dividends on Guaranteed Preferred
Beneficial Interests in Company's
Convertible Debentures (TECONS)............................. 1,653 1,653
Other expense.................................................. 572 3,454
-------------- --------------
76,967 74,842
-------------- --------------
Income (loss) before income taxes................................. 12,625 (4,594)
Provision (benefit) for income taxes.............................. 5,089 (1,838)
-------------- --------------
NET INCOME (LOSS)................................................. $ 7,536 $ (2,756)
============== ==============
EARNINGS (LOSS) PER SHARE:
BASIC:
Earnings (loss) per common share.................................. $ 0.43 $ (0.14)
=============== ==============
Weighted average common shares outstanding........................ 17,589 19,610
=============== ===============
DILUTED:
Earnings (loss) per common share.................................. $ 0.42 $ (0.14)
=============== ==============
Weighted average common and dilutive potential
common shares outstanding......................................... 17,886 19,610
=============== ==============
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)
Nine Months Ended September 30,
-------------------------------
2000 1999
---------- ----------
REVENUES:
Oil and gas revenues........................................... $ 230,656 $ 165,327
Gain on sale of assets, net.................................... -- 80,003
Interest and other income...................................... 3,085 4,421
-------------- --------------
233,741 249,751
-------------- --------------
COSTS AND EXPENSES:
Lease operating expenses....................................... 103,610 95,841
Exploration costs.............................................. 5,533 10,619
Depreciation, depletion and amortization....................... 49,885 63,556
Loss on sale of assets, net.................................... 14 --
General and administrative expenses............................ 13,391 11,835
Outsourcing fees............................................... 10,199 10,449
Interest expense............................................... 26,596 24,348
Dividends on Guaranteed Preferred
Beneficial Interests in Company's
Convertible Debentures (TECONS)............................. 4,959 4,959
Other expense.................................................. 4,419 6,433
-------------- --------------
218,606 228,040
-------------- --------------
Income before income taxes........................................ 15,135 21,711
Provision for income taxes........................................ 6,100 8,683
-------------- --------------
NET INCOME........................................................ $ 9,035 $ 13,028
============== ==============
EARNINGS PER SHARE:
BASIC:
Earnings per common share......................................... $ 0.51 $ 0.66
=============== ==============
Weighted average common shares outstanding........................ 17,663 19,768
=============== ==============
DILUTED:
Earnings per common share......................................... $ 0.50 $ 0.65
=============== ==============
Weighted average common and dilutive potential
common shares outstanding......................................... 18,013 19,902
=============== ==============
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)
Nine Months Ended September 30,
-------------------------------
2000 1999
--------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ............................................... $ 9,035 $ 13,028
Adjustments to reconcile net income to
net cash provided by/(used in) operating activities:
Depreciation, depletion and amortization ....... 49,885 63,556
Loss (gain) on sale of assets, net ............. 14 (80,003)
Dry hole costs ................................. 91 7,324
Amortization of other costs .................... 1,396 1,254
Debt modification costs ........................ -- 2,883
Deferred taxes ................................. 6,471 7,183
Mark to market of deferred compensation plan ... (53) 577
Other .......................................... 108 120
--------- ---------
66,947 15,922
Changes in assets and liabilities:
Accounts receivable ................................ (10,771) (13,234)
Accounts payable and accrued liabilities ........... 4,118 (7,174)
Other .............................................. 3,650 2,127
--------- ---------
NET CASH PROVIDED BY/(USED IN) OPERATING ACTIVITIES ...... 63,944 (2,359)
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties ................... (76,216) (41,849)
Acquisitions of oil and gas properties ................ -- (61,416)
Additions to gas plant facilities ..................... (126) (3,420)
Additions to other facilities ......................... (2,384) (8,938)
Proceeds from sales of properties ..................... 2,584 199,663
--------- ---------
NET CASH (USED IN)/PROVIDED BY INVESTING ACTIVITIES ...... (76,142) 84,040
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings .............................. 197,100 134,590
Payments of long-term debt ............................ (128,873) (195,267)
Deferred financing and modification costs ............. (4,964) (7,872)
Treasury stock purchases .............................. (12,540) (19,802)
Proceeds from issuance of common stock ................ 2,462 1,454
--------- ---------
NET CASH PROVIDED BY/(USED IN) FINANCING ACTIVITIES ...... 53,185 (86,897)
--------- ---------
Net increase (decrease) in cash and cash equivalents .. 40,987 (5,216)
Cash and cash equivalents at beginning of
period ............................................. 10,288 7,403
--------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD ............... $ 51,275 $ 2,187
========= =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of amounts capitalized) .............. $ 19,143 $ 23,133
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 ("SEC") 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 September 30, 2000 and December 31, 1999
and the results of operations and changes in cash flows for the periods
ended September 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").
The SEC is currently reviewing certain of the Company's historical
financial statements, reserve information and other information included
in the Company's periodic filings in conjunction with the Company's
filing of a shelf registration statement on Form S-3. In the course of
the review by the SEC of the registration statement, the Company may be
required to make changes to the description of its business, reserves,
financial statements and other information. While the Company believes
that its historical financial statements have been prepared in a manner
that complies, in all material respects, with generally accepted
accounting principles and the regulations published by the SEC, and that
its reserve and other disclosures are in accordance with applicable SEC
guidelines, comments by the SEC on the registration statement may require
modification or reformulation of the Company's financial statements,
reserves and other information previously filed with the SEC.
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
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NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
such deferred gains or losses at September 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
$32.6 million and $16.5 million in the third quarter of 2000 and 1999,
respectively. For the first nine months of 2000 and 1999, oil and gas
revenues were reduced by $83.9 million and $25.3 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 converted 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. In addition, the swap
arrangement effectively set the price at which the Company could
repurchase these Notes. In the third quarter of 2000, this swap
arrangement was settled, resulting in no significant impact to the
Company's results of operations.
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 cost-less 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
September 30, 2000, the market value of these hedge positions was a loss
of approximately $28.1 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 September 30, 2000, the market
value of these swaps was a loss of $64.0 million.
For 2002, the Company has entered into swap arrangements on 12,500 BOPD
for the first quarter at an average WTI price of $25.91 per barrel. For
the remainder of 2002, the Company purchased put options with a strike
price of $22.00 per barrel WTI, on 19,000 BOPD for the second quarter,
and on 14,000 BOPD for both the third and fourth quarters. At September
30, 2000, the market value of these hedge positions is a gain of $0.3
million. All of 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 that changes in the derivative's fair value be recognized currently
in earnings unless specific hedge accounting criteria are met. Accounting
for qualifying hedges allows derivative gains and losses to be reported
in other comprehensive income until the hedged transaction occurs, and
requires formal documentation and assessment of the effectiveness of
transactions that receive hedge accounting.
The Company must adopt SFAS No. 133 by January 1, 2001, and does not plan
to adopt early. On adoption, the provisions of this statement must be
applied prospectively. The Company has completed an inventory of all
known derivatives and is in the process of documenting the relevant hedge
relationships. The Company
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NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
expects that the adoption of SFAS No. 133 will increase the volatility of
other comprehensive income and results of operations. In general, the
amount of volatility will vary with the level of derivative activities
during any period. Although the Company currently believes that its
derivative financial instruments will qualify for hedge accounting under
SFAS No. 133, the Company has not yet determined the impact of the
implementation 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 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 had deferred tax assets, net of valuation allowances, of
$17.9 million and $24.0 million as of September 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 September 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 Republics of Congo and Ghana in West
Africa.
For the Nine Months Ended September 30,
---------------------------------------
2000 1999
-------------- --------------
(amounts in thousands)
Sales to unaffiliated customers:
Oil and gas - Domestic................................... $ 199,550 $ 144,583
Oil and gas - International.............................. 31,106 20,744
-------------- --------------
Total sales................................................... 230,656 165,327
Gain on sale of assets, net.............................. -- 80,003
Other revenues........................................... 3,085 4,421
-------------- --------------
Total revenues................................................ $ 233,741 $ 249,751
============== ==============
Operating profit before income taxes:
Oil and gas - Domestic (a)............................... $ 62,116 $ 72,539
Oil and gas - International.............................. 10,597 3,568
-------------- --------------
72,713 76,107
Unallocated corporate expenses................................ 26,023 25,089
Interest expense.............................................. 26,596 24,348
Dividends on TECONS........................................... 4,959 4,959
-------------- --------------
Income before income taxes............................... $ 15,135 $ 21,711
============== ==============
Depreciation, depletion and amortization:
Oil and gas - Domestic................................... $ 42,418 $ 56,212
Oil and gas - International.............................. 6,368 6,174
Other.................................................... 1,099 1,170
-------------- --------------
$ 49,885 $ 63,556
============== ==============
(a) Includes an $80.3 million gain on sale of the East Texas gas properties
for the nine months ended September 30, 1999.
5. LONG-TERM DEBT
Long-term debt consists of the following (amounts in thousands):
September 30, December 31,
2000 1999
------------- ------------
9 3/8% Senior Subordinated Notes due 2010(a)........................... $ 150,000 $ ---
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(b)................................................ -- 81,000
OPIC credit facility................................................... -- 750
---------- ----------
Total debt..................................................... 409,727 341,500
Less: current maturities............................................... -- (750)
---------- ----------
Long-term debt......................................................... $ 409,727 $ 340,750
========== ==========
(a) In September 2000, the Company issued $150.0 million of 9 3/8% Senior
Subordinated Notes due October 1, 2010 ("9 3/8% Notes"). Interest on the
9 3/8% Notes accrues at the rate of 9 3/8% per annum
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NUEVO ENERGY COMPANY
NOTED TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
and is payable semi-annually in arrears on April 1 and October 1. Net
proceeds from this offering of $146.6 million were used to repay
outstanding borrowings under the Company's credit facility and for
operating expenses and other general corporate purposes.
(b) 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, 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 September 30, 2000, was $225.0 million, which is $75.0
million less than the previous borrowing base due to the net effect of
the Company's higher asset valuation as of June 30, 2000, and its higher
fixed interest costs associated with the issuance of the 9 3/8% Notes.
The Company was in compliance with all covenants as of September 30,
2000, and does not anticipate any issues of non-compliance arising in the
foreseeable future. At September 30, 2000, there were no outstanding
borrowings under the revolving credit agreement. Accordingly, $225.0
million of credit capacity was unused and available at September 30,
2000.
6. EARNINGS (LOSS) PER SHARE COMPUTATION
SFAS No. 128 requires a reconciliation of the numerator (income or loss)
and denominator (shares) of the basic earnings (loss) per share ("EPS")
computation to the numerator and denominator of the diluted EPS
computation. In the three-month period ended September 30, 1999, there
were no potential dilutive common shares. The Company's reconciliation is
as follows (amounts in thousands):
For the Three Months Ended September 30,
----------------------------------------------------
2000 1999
-------------------------- ------------------------
Income Shares Loss Shares
------------ ------------ ----------- -----------
Earnings (loss) per Common share - Basic........... $ 7,536 17,589 $ (2,756) 19,610
Effect of dilutive securities:
Stock options...................................... -- 297 -- --
------------ ------------ ----------- -----------
Earnings (loss) per Common share - Diluted......... $ 7,536 17,886 $ (2,756) 19,610
============ ============ =========== ===========
For the Nine Months Ended September 30,
----------------------------------------------------
2000 1999
-------------------------- ------------------------
Income Shares Income Shares
------------ ------------ ----------- -----------
Earnings per Common share - Basic.................. $ 9,035 17,663 $ 13,028 19,768
Effect of dilutive securities:
Stock options...................................... -- 350 -- 134
------------ ------------ ----------- -----------
Earnings per Common share - Diluted................ $ 9,035 18,013 $ 13,028 19,902
============ ============ =========== ===========
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 was dismissed, the defendants paid the plaintiffs $12.0
million and the lease agreement was amended. Nuevo's working interest in
these properties is 20%, and its share of the settlement payment was
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
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NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
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, where appropriate,
strengthened its internal control procedures. In August 2000, the Company
recorded $1.5 million of other income for a partial reimbursement of
these previously expensed funds, resulting from the negotiated settlement
of a related legal claim.
In September 1997, there was a spill of crude oil into the Santa Barbara
Channel from a pipeline that connects 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 $48.0 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 $64.6 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.
12
13
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
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 per Bbl. under the agreement
(determined based on the near month delivery of WTI crude oil on the
NYMEX) is escalated at 3% per year and the maximum price of $21.75 per
Bbl. on the NYMEX is escalated at 3% per year. Minimum and maximum prices
are reduced to reflect the field level price by subtracting a fixed
differential established for each field. The reduction was established at
approximately the differential between actual sales prices and NYMEX
prices in effect in 1995 ($4.34 per Bbl. weighted average for all the
properties acquired from Unocal). 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 28% of the gross Point Pedernales
production, or 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 an adjusted net gain on sale of
approximately $780,000. Also, the Company sold certain of its non-core
assets during the third quarter of 2000, recognizing a net loss of
approximately $500,000.
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 September 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
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
11. LEGAL PROCEEDINGS
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. 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. 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.
14
15
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"), Section 21E of the Securities Exchange Act of 1934 ("Exchange
Act"), and the Private Securities Litigation Act of 1995. 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 ("SEC"). 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.
SEC REVIEW
The SEC is currently reviewing certain of the Company's historical
financial statements, reserve information and other information included
in the Company's periodic filings in conjunction with the Company's
filing of a shelf registration statement on Form S-3. In the course of
the review by the SEC of the registration statement, the Company may be
required to make changes to the description of its business, reserves,
financial statements and other information. While the Company believes
that its historical financial statements have been prepared in a manner
that complies, in all material respects, with generally accepted
accounting principles and the regulations published by the SEC, and that
its reserve and other disclosures are in accordance with applicable SEC
guidelines, comments by the SEC on the registration statement may require
modification or reformulation of the Company's financial statements,
reserves and other information previously filed with the SEC.
CAPITAL RESOURCES AND LIQUIDITY
Since its 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 $63.9 million and $(2.4) million for the nine months ended
September 30, 2000 and 1999, respectively. The Company invested $76.2
million and $103.3 million in oil and gas properties for the nine months
ended September 30, 2000 and 1999, respectively.
The current borrowing base on the Company's credit facility is $225.0
million. At September 30, 2000, there were no outstanding borrowings
under the revolving credit agreement. Accordingly, $225.0 million of
credit capacity was unused and available at September 30, 2000. At
September 30, 2000, the Company had working capital of $46.6 million.
On September 26, 2000, the Company issued $150.0 million of 9 3/8% Senior
Subordinated Notes due October 1, 2010 ("9 3/8% Notes"). Net proceeds
from this offering of $146.6 million were used to repay outstanding
borrowings under the Company's credit facility and for operating expenses
and other general corporate purposes.
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
15
16
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
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 September 30, 2000, was $225.0 million, which is $75.0 million less
than the previous borrowing base due to the net effect of the Company's
higher asset valuation as of June 30, 2000, and its higher fixed interest
costs associated with the recently issued 9 3/8% Notes. The Company was
in compliance with all covenants as of September 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 delay resulted from a political initiative that, if passed,
would have subjected certain future development projects, such as Brea
Highlands, to a public vote. The initiative was defeated in the November
7, 2000 election. Nevertheless, due to divisiveness within the City of
Brea over the issue of hillside development, the Company removed its
entitlement application from the City of Brea and submitted an
entitlement application with Orange County under the project name "Tonner
Hills". 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.
CAPITAL EXPENDITURES
As mentioned above, the Company decided to defer $20.0 million of its
original $140.0 million 2000 capital budget, as a result of expected
delays in the potential sale or joint venture of its Brea Highlands real
estate development. Under the revised 2000 capital budget of $120.0
million, the Company anticipates spending approximately $37.0 million on
development activities, 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 nine months of 2000
and 1999 are as follows (amounts in thousands):
For the Nine Months Ended
September 30,
-----------------------------
2000 1999
--------- ---------
Domestic $ 75,726 $ 25,622
International 7,536 22,148
--------- ---------
Total $ 83,262 $ 47,770
========= =========
The following is a description of significant exploration and development
activity during the first nine months of 2000.
Exploration Activity
Domestic
During 2000, the Company drilled a successful exploratory well on its
Star Fee lease in the Cymric Field in California, which was acquired from
Texaco in 1999. The Star Fee 701 deep well tested at a rate of over 900
barrels of oil per day ("BOPD") and 1.2 million cubic feet of gas per
day, and has already produced over 100,000 equivalent barrels since
August 2000. This well is currently producing at rates over 1,000 BOPD.
As
16
17
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
a result of this success, additional exploratory wells have been
scheduled for drilling in 2001 to further test the deep geologic model.
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. In October 2000, the Company transferred a 25% participating
interest in this permit to a large U.S.-based independent oil and gas
company. Nuevo will continue to be the operator of the permit and
currently has a 75% participating interest. The Company plans to drill
its first exploratory well on the concession late this year or early 2001
and continues to hold discussions with parties considering the
acquisition of an interest in this concession. 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 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 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 221 development wells, of which 60 were
injectors, in the first nine months of 2000, most of the wells relate to
the interests acquired from Texaco in 1999. The Company completed the
first phase of its development-drilling program on its Cymric Field Star
Fee property 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 65 wells. The Company expects this
program to be completed by the end of
17
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NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
the year. The wells drilled to date are currently producing at a combined
rate of 5,800 BOPD. Year to date, the Company drilled 133 wells on its
Cymric Field (four of which were horizontal wells and 21 of which were
steam injectors), 45 wells on its Belridge Field (ten of which were
horizontal wells and 33 of which were steam injectors), and 37 wells at
Midway Sunset (one of which was horizontal and six of which were
injectors). In addition to the development activity in California, the
Company successfully drilled two offshore wells at its Huntington Beach
Field. These two wells have been completed and are producing 600 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 start-up of the first self-generation project cost approximately $4.5
million and has resulted 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 to date. 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 Company expects this plant
to be online and operational by year-end. The water plant is expected to
cost approximately $6.2 million to construct.
International
During the first nine months of 2000, the Company drilled its first
horizontal test well on its Martin Hill project in Alberta, Canada. The
Company has a 50% interest in over 22,000 acres on this project. The
Company plans to install a steam generator and begin a pilot thermal
process that will be conducted this winter to test this zone.
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 September 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
$32.6 million and $16.5 million in the third quarter of 2000 and 1999,
respectively. For the first nine months of 2000 and 1999, oil and gas
revenues were reduced by $83.9 million and $25.3 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 converted 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. In addition, the swap
arrangement effectively set the price at which the Company could
repurchase these Notes. In the third quarter of 2000, this swap
arrangement was settled, resulting in no significant impact to the
Company's results of operations.
18
19
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
For 2000, the Company entered into swap contracts on 16,500 BOPD, at an
average West Texas Intermediate ("WTI") price of $17.94 per barrel. The
Company also entered into cost-less 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 September 30,
2000, the market value of these hedge positions was a loss of
approximately $28.1 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 September 30, 2000, the market
value of these swaps was a loss of $64.0 million.
For 2002, the Company has entered into swap arrangements on 12,500 BOPD
for the first quarter at an average WTI price of $25.91 per barrel. For
the remainder of 2002, the Company purchased put options with a strike
price of $22.00 per barrel WTI, on 19,000 BOPD for the second quarter,
and on 14,000 BOPD for both the third and fourth quarters. At September
30, 2000, the market value of these hedge positions is a gain of $0.3
million. All of 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.
CRUDE OIL AGREEMENT
In February 2000, the Company entered into a 15-year contract, effective
January 1, 2000, to sell substantially all of its current and future
California crude oil production to Tosco Corporation. The contract
provides pricing based on a fixed percentage of the NYMEX crude oil price
for each type of crude oil that Nuevo produces in California. Therefore,
the actual price received as a percentage of NYMEX will vary with the
Company's production mix. Based on the Company's current production mix,
the price received by Nuevo for its California production is expected to
average at approximately 72% of WTI. While the contract does not reduce
the Company's exposure to price volatility, it does effectively eliminate
the basis differential risk between the NYMEX price and the field price
of the Company's California oil production.
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 per Bbl. under the agreement
(determined based on the near month delivery of WTI crude oil on the
NYMEX) is escalated at 3% per year and the maximum price of $21.75 per
Bbl. on the NYMEX is escalated at 3% per year. Minimum and maximum prices
are reduced to reflect the field level price by subtracting a fixed
differential established for each field. The reduction was established at
approximately the differential between actual sales prices and NYMEX
prices in effect in 1995 ($4.34 per Bbl. weighted average for all the
properties acquired from Unocal). 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
19
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NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
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 28% of the gross Point Pedernales
production, or 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 that changes in the derivative's fair value be recognized currently
in earnings unless specific hedge accounting criteria are met. Accounting
for qualifying hedges allows derivative gains and losses to be reported
in other comprehensive income until the hedged transaction occurs, and
requires formal documentation and assessment of the effectiveness of
transactions that receive hedge accounting.
The Company must adopt SFAS No. 133 by January 1, 2001, and does not plan
to adopt early. On adoption, the provisions of this statement must be
applied prospectively. The Company has completed an inventory of all
known derivatives and is in the process of documenting the relevant hedge
relationships. The Company expects that the adoption of SFAS No. 133 will
increase the volatility of other comprehensive income and results of
operations. In general, the amount of volatility will vary with the level
of derivative activities during any period. Although the Company
currently believes that its derivative financial instruments will qualify
for hedge accounting under SFAS No. 133, the Company has not yet
determined the impact of the implementation 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 September 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 had deferred tax assets, net of valuation allowances, of
$17.9 million and $24.0 million as of September 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.
20
21
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
RESULTS OF OPERATIONS (THREE MONTHS ENDED SEPTEMBER 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 September 30,
------------------- %
Increase/
2000 1999 (Decrease)
----- ----- ----------
PRODUCTION:
Oil and condensate - Domestic (MBBLS) ................. 3,999 3,962 1%
Oil and condensate - International (MBBLS) ............ 479 501 (4%)
----- ----- ----
Oil and condensate - Total (MBBLS) .................... 4,478 4,463 0%
Natural gas - Domestic (MMCF) ......................... 3,636 4,926 (26%)
Natural gas liquids - Domestic (MBBLS) ................ 48 54 (11%)
Equivalent barrels of production - Domestic (MBOE) .... 4,652 4,837 (4%)
Equivalent barrels of production -
International (MBOE) .................................. 479 501 (4%)
----- -----
Equivalent barrels of production - Total (MBOE) ....... 5,131 5,338 (4%)
AVERAGE SALES PRICE:
Oil and condensate - Domestic ......................... $14.51 $11.39 27%
Oil and condensate - International .................... $19.07 $19.62 (3%)
Oil and condensate - Total ............................ $15.00 $12.31 22%
Natural gas - Domestic ................................ $5.24 $2.53 107%
LEASE OPERATING EXPENSE:
Average unit production cost(1) per BOE - Domestic .... $7.46 $6.78 10%
Average unit production cost(1) per BOE -
International ......................................... $7.31 $5.65 29%
Average unit production cost(1) per BOE - Total ....... $7.45 $6.67 12%
(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 September 30, 2000, were $87.3
million, or 27% higher than oil and gas revenues for the same period in 1999.
This increase is primarily due to a 22% increase in realized oil prices and a
107% increase in realized gas prices. These increases were partially offset by a
26% decrease in gas production, which was primarily attributable to asset sales
and natural field declines from reduced capital spending. Third quarter 2000 oil
price realizations reflect hedging losses of $32.6 million, or $7.27 per barrel,
compared to third quarter 1999 hedging losses of $16.5 million, or $3.70 per
barrel.
The Company recorded three non-recurring items during the third quarter of 2000,
which together have a net immaterial impact on oil and gas revenues. The first
non-recurring item was a $3.5 million decrease (net of royalties) in gas
revenues resulting from a metering error in the Company's Monument Junction
Field in California. This metering error overstated gas volumes and occurred
over a two and a half-year period. The error was identified and corrected in the
third quarter of 2000. The overstatement associated with this adjustment was
also recorded in lease
21
22
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
operating expenses (see "Lease Operating Expenses" below), as the Company
consumes the Monument Junction gas production in its thermal operations at
nearby fields. The second non-recurring item was a $2.1 million revenue
receivable for royalties that had been overpaid in prior periods. This item is
reflected as an increase in oil revenues. The third non-recurring item was a
$1.3 million gas balancing receivable that increased gas revenues. This gas
balancing receivable related to production from Four Isle Dome since 1997.
Domestic: Oil and gas revenues for the three months ended September 30, 2000,
were 32% higher than oil and gas revenues for the same period in 1999. This
increase is primarily due to a 27% improvement in average realized oil prices
and a 107% improvement in average realized gas prices, partially offset by a 26%
decrease in gas production. The realized oil price of $14.51 per barrel for the
third quarter of 2000 includes negative hedging results of $8.39 per barrel of
oil, compared to negative hedging results of $4.30 per barrel of oil for the
third quarter of 1999.
International: Oil revenues for the three months ended September 30, 2000,
decreased 7% as compared to the same period in 1999. This decrease resulted from
a 3% decrease in oil price realizations to $19.07 per barrel, coupled with a 4%
decrease in oil production. The realized oil price for the third quarter of 2000
includes hedging gains of $2.06 per barrel of oil, compared to hedging gains of
$1.06 per barrel in the third quarter of 1999.
Loss/Gain on Sale of Assets, net:
The net loss on sale of assets for the three months ended September 30, 2000,
was $0.5 million, primarily representing a $1.2 million loss on the sale of
certain non-core East Texas Chalk properties, which was partially offset by a
$0.7 million gain on the sale of a waste water disposal plant site in
California. Gain on sale of assets, net, for the three months ended September
30, 1999, was $(0.3) million, representing a negative revision for final
accounting adjustments in connection with the Company's sale of the Illini
pipeline and certain insignificant oil and gas properties.
Interest and Other Income:
Interest and other income for the three months ended September 30, 2000,
includes $1.5 million for a partial reimbursement of previously expensed funds,
resulting from a negotiated settlement of a legal claim (see Note 7 to the Notes
to Condensed Consolidated Financial Statements), as well as several individually
insignificant items. Interest and other income for the three months ended
September 30, 1999, includes a $0.6 million gain on the sale of an
unconsolidated subsidiary, as well as several individually insignificant items.
Expenses
Lease Operating Expenses:
Lease operating expenses for the three months ended September 30, 2000, were
$38.2 million, or 7% higher than for the three months ended September 30, 1999.
Lease operating expenses per barrel of oil equivalent ("BOE") were $7.45 in the
third quarter of 2000, compared to $6.67 in the same period in 1999. The
increase is primarily due to a $7.6 million increase in steam costs resulting
from higher natural gas prices and an increase in gas volumes consumed in
connection with the Company's thermal operations at its Star Fee lease in the
Cymric Field. Offsetting this increase in steam costs is a $3.8 million downward
adjustment to steam costs that resulted from a metering error at the Company's
Monument Junction Field. This error overstated gas volumes and occurred over a
two and a half-year period. The error was identified and corrected in the third
quarter of 2000. The overstatement associated with this adjustment was also
recorded in gas revenues (see "Oil and Gas Revenues" above), as the Company
produces the Monument Junction gas that is consumed in its thermal operations.
Domestic: Lease operating expenses per BOE were $7.46 in the third quarter of
2000, compared to $6.78 in the same period in 1999. Higher steam costs
contributed to the higher lease operating expenses per BOE quarter over quarter.
22
23
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
International: Lease operating expenses per BOE were $7.31 in the third quarter
of 2000, compared to $5.65 in the same period in 1999. This increase is due to
an increase in workovers, as well as the resulting 4% decrease in production.
Exploration Costs:
Exploration costs, including geological and geophysical ("G&G") costs, dry hole
costs, delay rentals and expensed project costs, were $0.8 million and $0.6
million for the three months ended September 30, 2000 and 1999, respectively.
For the three months ended September 30, 2000, exploration costs were comprised
of $0.7 million in G&G (primarily for consulting costs and 2-D seismic
processing in California) and $0.1 million of miscellaneous project costs. For
the three months ended September 30, 1999, exploration costs were comprised of
$0.3 million of expensed project costs, $0.2 million in G&G, and $0.1 million in
delay rentals.
General and Administrative Expenses:
General and administrative expenses were $3.9 million and $4.6 million in the
three months ended September 30, 2000 and 1999, respectively. The 15% decrease
is due primarily to a $0.5 million decrease in the fair market value of
securities in the Company's deferred compensation plan. The remaining decrease
is made up of individually insignificant items.
Interest Expense:
Interest expense of $9.8 million for the three months ended September 30, 2000,
increased 23% as compared to interest expense in the same period in 1999. The
increase is primarily attributable to an increase in outstanding borrowings
under the Company's credit facility plus higher interest rates on those
outstanding borrowings during the third quarter of 2000. On September 26, 2000,
all borrowings outstanding under the credit facility were paid off with net
proceeds received from the Company's issuance of the 9 3/8% Notes (see Note 5 to
the Notes to Condensed Consolidated Financial Statements).
Other Expense:
The $2.9 million decrease in other expense from the third quarter of 1999 to the
third quarter of 2000 relates to $2.9 million of third-party fees incurred in
the third quarter of 1999 in connection with the exchange of the Company's
senior subordinated notes.
Net Income (Loss)
Net income of $7.5 million, $0.43 per common share - basic and $0.42 per common
share - diluted, was reported for the three months ended September 30, 2000, as
compared to a net loss of $2.8 million, $0.14 per common share - basic and
diluted, reported for the same period in 1999.
23
24
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
RESULTS OF OPERATIONS (NINE MONTHS ENDED SEPTEMBER 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:
Nine Months
Ended September 30, %
------------------------ Increase/
2000 1999 (Decrease)
---------- ----------- ----------
PRODUCTION:
Oil and condensate - Domestic (MBBLS)..................... 11,352 11,777 (4%)
Oil and condensate - International (MBBLS)................ 1,457 1,350 8%
---------- ----------
Oil and condensate - Total (MBBLS)........................ 12,809 13,127 (2%)
Natural gas - Domestic (MMCF)............................. 11,447 13,153 (13%)
Natural gas liquids - Domestic (MBBLS).................... 133 147 (10%)
Equivalent barrels of production - Domestic (MBOE)........ 13,393 14,116 (5%)
Equivalent barrels of production - International (MBOE)... 1,457 1,350 8%
---------- ----------
Equivalent barrels of production - Total (MBOE)........... 14,850 15,466 (4%)
AVERAGE SALES PRICE:
Oil and condensate - Domestic............................. $ 13.61 $ 9.58 42%
Oil and condensate - International........................ $ 21.35 $ 15.37 39%
Oil and condensate - Total................................ $ 14.49 $ 10.17 42%
Natural gas - Domestic.................................... $ 3.65 $ 2.12 72%
LEASE OPERATING EXPENSE:
Average unit production cost(1) per BOE - Domestic........ $ 6.96 $ 6.14 13%
Average unit production cost(1) per BOE - International... $ 7.12 $ 6.78 5%
Average unit production cost(1) per BOE - Total........... $ 6.98 $ 6.20 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 nine months ended September 30, 2000, were $230.7
million, or 40% higher than oil and gas revenues for the same period in 1999.
This increase is primarily due to a 42% increase in realized oil prices and a
72% 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 nine month 2000 oil price realizations reflect hedging losses of
$83.9 million, or $6.55 per barrel, compared to hedging losses of $25.3 million,
or $1.93 per barrel in the first nine months of 1999.
Domestic: Oil and gas revenues for the nine months ended September 30, 2000,
were 38% higher than oil and gas revenues for the same period in 1999. This
increase is primarily due to a 42% improvement in average realized oil prices
and a 72% improvement in average realized gas prices, partially offset by a 13%
decrease in gas production and a 4% decrease in oil production. The 5% decrease
in total production is a result of asset sales, reduced capital
24
25
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Spending in 1999 and production interruptions due to pump replacements and
brown-outs in California during recent periods of extreme temperatures. The
realized oil price of $13.61 per barrel for the first nine months of 2000
includes negative hedging results of $86.9 million, or $7.66 per barrel of oil,
compared to hedging losses of $26.7 million, or $2.26 per barrel in the first
nine months of 1999.
International: Oil revenues for the nine months ended September 30, 2000,
increased 50% compared to the same period in 1999. This significant increase
resulted from a 39% increase in oil price realizations to $21.35 per barrel,
coupled with an 8% increase in oil production. The realized oil price for the
first nine months of 2000 includes hedging gains of $3.0 million, or $2.08 per
barrel of oil, compared to hedging gains of $1.4 million, or $1.01 per barrel in
the first nine months of 1999.
Loss/Gain on Sale of Assets, net:
The net loss on sale of assets for the nine months ended September 30, 2000, was
$14,000, primarily representing a $1.2 million loss on the sale of certain
non-core East Texas Chalk properties, which was almost entirely offset by a $0.7
million gain on the sale of a waste water disposal plant site in California and
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 nine months ended September 30, 1999, was $80.0 million, primarily
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 nine months ended September 30, 2000, includes
$1.5 million for a partial reimbursement of previously expensed funds, resulting
from a negotiated settlement of a legal claim (see Note 7 to the Notes to
Condensed Consolidated Financial Statements), as well as several individually
insignificant items. Interest and other income for the nine months ended
September 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 plus a $0.6 million gain
on the sale of an unconsolidated subsidiary, as well as several individually
insignificant items.
Expenses
Lease Operating Expenses:
Lease operating expenses for the nine months ended September 30, 2000, were
$103.6 million, or 8% higher than for the nine months ended September 30, 1999.
This increase is primarily due to a $10.8 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 $6.98 in the first nine
months of 2000, compared to $6.20 in the same period in 1999. The per barrel
increase is primarily due to a $0.76 per BOE increase in steam costs, as well as
the 4% decrease in total production.
Domestic: Lease operating expenses per BOE were $6.96 in the first nine months
of 2000, compared to $6.14 in the same period in 1999. Higher steam costs
accounted for $0.86 of the per BOE increase, partially offset by lower field
costs. The remaining increase is attributable to the 5% decrease in production.
International: Lease operating expenses per BOE were $7.12 in the first nine
months of 2000, compared to $6.78 in the same period in 1999. The increase in
lease operating expenses per BOE is primarily attributable to the 8% increase in
production.
Exploration Costs:
Exploration costs, including G&G costs, dry hole costs, delay rentals and
expensed project costs, were $5.5 million and $10.6 million for the nine months
ended September 30, 2000 and 1999, respectively. For the nine months ended
September 30, 2000, exploration costs were comprised of $4.4 million in G&G
(primarily for 3-D seismic acquisition and processing in the Accra-Keta prospect
offshore Ghana), $0.8 million of other project costs, $0.2 million in delay
25
26
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
rentals, and $0.1 million in dry hole costs,. For the nine months ended
September 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), $1.7
million in G&G, $1.2 million of expensed project costs, and $0.4 million in
delay rentals.
Depreciation, Depletion and Amortization:
Depreciation, depletion and amortization for the nine months ended September 30,
2000, reflects a 22% 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 $13.4 million and $11.8 million for the
nine months ended September 30, 2000 and 1999, respectively. The 13% increase is
due primarily to a $1.4 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 $26.6 million for the nine months ended September 30, 2000,
increased 9% as compared to interest expense in the same period in 1999. The
increase is primarily attributable to an increase in outstanding borrowings
under the Company's credit facility plus higher interest rates on those
outstanding borrowings. On September 26, 2000, all borrowings outstanding under
the credit facility were paid off with net proceeds received from the Company's
issuance of the 9 3/8% Notes (see Note 5 to the Notes to Condensed Consolidated
Financial Statements). The increase is also due 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 31% decrease in other expense from the first nine months of 1999 to the
first nine months of 2000 is due to a number of items. In 1999, the Company
incurred $2.9 million of third-party fees in the third quarter of 1999 in
connection with the exchange of its senior subordinated notes. Additionally, 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. In 2000, the Company recorded a $2.0
million accrual for a lawsuit settlement (see Note 7 to the Notes to Condensed
Consolidated Financial Statements) and $0.8 million in costs to evaluate
potential business transactions. The remaining decrease is made up of
individually insignificant items.
Net Income
Net income of $9.0 million, $0.51 per common share - basic and $0.50 per common
share - diluted, was reported for the nine months ended September 30, 2000, as
compared to net income of $13.0 million, $0.66 per common share - basic and
$0.65 per common share - diluted, reported for the same period in 1999.
26
27
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.
27
28
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 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) EXHIBITS
3. Articles of Incorporation and bylaws.
3.1 Certificate of Incorporation of Nuevo Energy Company
(Incorporated by reference from Exhibit 3.1 to Quarterly
Report on Form 10-Q for the quarterly period ended June 30,
1999).
3.2 Certificate of Amendment to the Certificate of Incorporation
of Nuevo Energy Company (Incorporated by reference from
Exhibit 3.2 to Quarterly Report on Form 10-Q for the
quarterly period ended June 30, 1999).
3.3 Bylaws of Nuevo Energy Company (Incorporated by reference
from Exhibit 3.3 to Quarterly Report on Form 10-Q for the
quarterly period ended June 30, 1999).
3.4 Amendment to section 3.1 of the Bylaws of Nuevo Energy
Company (Incorporated by reference from Exhibit 3.4 to
Quarterly Report on Form 10-Q for the quarterly period ended
June 30, 1999).
4. Instruments defining the rights of security holders, including
indentures
4.12 Indenture dated September 26, 2000, between Nuevo Energy
Company and State Street Bank and Trust Company as the
Trustee - 9 3/8% Senior Subordinated Notes due 2010.
4.13 Registration Agreement dated September 26, 2000 between
Nuevo Energy Company and Banc of America Securities LLC,
Banc One Capital Markets, Inc. and J.P. Morgan & Co.
27. Financial Data Schedule
(b) Reports on Form 8-K
No reports on Form 8-K have been filed during the three-month period
ended September 30, 2000.
28
29
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: November 14, 2000 By: /s/ Douglas L. Foshee
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Douglas L. Foshee
Chairman, President and Chief Executive
Officer
Date: November 14, 2000 By: /s/ Robert M. King
----------------- -------------------------------------
Robert M. King
Senior Vice President and Chief
Financial Officer
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