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 MARCH 31, 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 May 10, 2000, the number of outstanding shares of the Registrant's common
stock was 17,600,635.
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NUEVO ENERGY COMPANY
INDEX
PAGE
NUMBER
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
.
Condensed Consolidated Balance Sheets:
March 31, 2000 (Unaudited) and December 31, 1999........................ 3
Condensed Consolidated Statements of Operations (Unaudited):
Three months ended March 31, 2000 and March 31, 1999.................... 5
Condensed Consolidated Statements of Cash Flows (Unaudited):
Three months ended March 31, 2000 and March 31, 1999.................... 6
Notes to Condensed Consolidated Financial Statements (Unaudited)................. 7
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.... 14
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk............................... 22
PART II. OTHER INFORMATION........................................................................ 23
2
3
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Amounts in Thousands)
ASSETS
March 31, 2000 December 31, 1999
-------------- -----------------
(Unaudited)
CURRENT ASSETS:
Cash and cash equivalents..................................... $ 3,746 $ 10,288
Accounts receivable........................................... 35,070 45,004
Product inventory............................................. 6,082 4,610
Prepaid expenses and other.................................... 3,690 6,389
---------- ----------
Total current assets........................................ 48,588 66,291
---------- ----------
PROPERTY AND EQUIPMENT, AT COST:
Land.......................................................... 51,017 51,017
Oil and gas properties (successful efforts method)............ 1,015,432 1,002,779
Gas plant facilities.......................................... 12,020 12,140
Other facilities.............................................. 12,271 11,874
---------- ----------
1,090,740 1,077,810
Accumulated depreciation, depletion and
amortization................................................ (445,588) (429,349)
---------- ----------
645,152 648,461
---------- ----------
DEFERRED TAX ASSETS, NET....................................... 23,415 24,005
OTHER ASSETS................................................... 20,715 21,273
---------- ----------
$ 737,870 $ 760,030
========== ==========
See accompanying notes to condensed consolidated financial statements.
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4
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS - Continued
(Amounts in Thousands, Except Share Data)
LIABILITIES AND STOCKHOLDERS' EQUITY
March 31, 2000 December 31,1999
-------------- ----------------
(Unaudited)
CURRENT LIABILITIES:
Accounts payable .......................................... $ 13,195 $ 20,492
Accrued interest........................................... 8,431 2,353
Accrued liabilities........................................ 28,677 37,755
Current maturities of long-term debt....................... 375 750
-------- --------
Total current liabilities............................... 50,678 61,350
-------- --------
LONG-TERM DEBT, NET OF CURRENT MATURITIES..................... 338,752 340,750
OTHER LONG-TERM LIABILITIES................................... 8,914 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, 20,548,271 and 20,437,371 shares issued and
17,430,793 and 17,931,393 shares outstanding at March
31, 2000 and December 31, 1999, respectively .............. 205 204
Additional paid-in capital................................. 359,761 357,855
Treasury stock, at cost, 2,961,996 and 2,430,074 shares, at
March 31, 2000 and December 31, 1999, respectively......... (61,120) (49,605)
Stock held by benefit trust, 155,482 and 75,904 shares, at
March 31, 2000 and December 31, 1999, respectively......... (3,283) (3,184)
Deferred stock compensation................................ (266) (216)
Accumulated deficit........................................ (70,771) (71,416)
-------- --------
Total stockholders' equity.............................. 224,526 233,638
-------- --------
$737,870 $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 March 31,
----------------------------
2000 1999
---- ----
REVENUES:
Oil and gas revenues........................................... $70,729 $ 43,464
Gain on sale of assets, net.................................... 140 81,699
Interest and other income...................................... 626 1,480
------- --------
71,495 126,643
------- --------
COSTS AND EXPENSES:
Lease operating expenses....................................... 31,111 29,914
Exploration costs.............................................. 3,254 2,125
Depreciation, depletion and amortization....................... 16,241 23,320
General and administrative expenses............................ 5,372 3,832
Outsourcing fees............................................... 3,333 3,210
Interest expense............................................... 8,290 7,999
Dividends on Guaranteed Preferred
Beneficial Interests in Company's
Convertible Debentures (TECONS)............................. 1,653 1,653
Other expense.................................................. 1,160 2,522
------- --------
70,414 74,575
------- --------
Income before income taxes........................................ 1,081 52,068
Provision for income taxes........................................ 436 20,726
------- --------
NET INCOME........................................................ $ 645 $ 31,342
======= ========
EARNINGS PER SHARE:
BASIC:
Earnings per common share......................................... $ 0.04 $ 1.58
======= ========
Weighted average common shares outstanding........................ 17,814 19,840
======= ========
DILUTED:
Earnings per common share......................................... $ 0.04 $ 1.58
======= ========
Weighted average common and dilutive potential
common shares outstanding......................................... 18,209 19,840
======= ========
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)
Three Months Ended March 31,
----------------------------
2000 1999
------ -------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ............................................... $ 645 $ 31,342
Adjustments to reconcile net income to
net cash provided by/(used in) operating activities:
Depreciation, depletion and amortization ....... 16,241 23,320
Gain on sale of assets, net .................... (140) (81,699)
Dry hole costs ................................. (44) 827
Amortization of other costs .................... 444 405
Deferred taxes ................................. 796 14,626
Appreciation of deferred compensation plan ..... 432 152
Mark to market of liability management swap .... 781 --
Other .......................................... 33 --
-------- ---------
19,188 (11,027)
Changes in assets and liabilities:
Accounts receivable ............................ 9,934 334
Accounts payable and accrued liabilities ....... (10,297) (4,287)
Other .......................................... (251) 4,548
-------- ---------
NET CASH PROVIDED BY/(USED IN) OPERATING ACTIVITIES ...... 18,574 (10,432)
-------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties ................... (12,223) (15,630)
Additions to gas plant facilities ..................... (126) (494)
Additions to other facilities ......................... (398) (1,057)
Proceeds from sales of properties ..................... -- 192,583
-------- ---------
NET CASH (USED IN)/PROVIDED BY INVESTING ACTIVITIES ...... (12,747) 175,402
-------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings .............................. 8,025 86,590
Payments of long-term debt ............................ (10,398) (140,415)
Treasury stock purchases .............................. (11,614) --
Proceeds from issuance of common stock ................ 1,618 --
-------- ---------
NET CASH USED IN FINANCING ACTIVITIES .................... (12,369) (53,825)
-------- ---------
Net (decrease)/increase in cash and cash equivalents .. (6,542) 111,145
Cash and cash equivalents at beginning of
period ............................................. 10,288 7,403
-------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD ............... $ 3,746 $ 118,548
======== =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of amounts capitalized) .............. $ 1,769 $ 2,306
Income taxes ....................................... $ -- $ --
See accompanying notes to condensed consolidated financial statements.
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NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The accompanying unaudited condensed consolidated financial statements
have been prepared in accordance with the rules and regulations of the
Securities and Exchange Commission and, therefore, do not include all
disclosures required by generally accepted accounting principles.
However, in the opinion of management, these statements include all
adjustments, which are of a normal recurring nature, necessary to present
fairly the financial position at March 31, 2000 and December 31, 1999 and
the results of operations and changes in cash flows for the periods ended
March 31, 2000 and 1999. These financial statements should be read in
conjunction with the financial statements and notes to financial
statements in the 1999 Form 10-K of Nuevo Energy Company (the "Company").
USE OF ESTIMATES
In order to prepare these financial statements in conformity with
generally accepted accounting principles, management of the Company has
made a number of estimates and assumptions relating to the reporting of
assets and liabilities and the disclosure of contingent assets and
liabilities, as well as reserve information, which affects the depletion
calculation. Actual results could differ from those estimates.
COMPREHENSIVE INCOME
Comprehensive income includes net income and all changes in other
comprehensive income including, among other things, foreign currency
translation adjustments, and unrealized gains and losses on certain
investments in debt and equity securities. There are no differences
between comprehensive income and net income 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 is sold.
There were no such deferred gains or losses at March 31, 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
$26.5 million and increased by $0.2 million in the first quarter of 2000
and 1999, respectively.
On February 26, 1999, the Company entered into a swap arrangement with a
major financial institution that effectively converts the interest rate
on $16.4 million notional amount of the 9 1/2% Senior Subordinated Notes
due 2008 ("Notes") to a variable LIBOR-based rate. On February 25, 2000,
this arrangement was extended through February 26, 2001. Amounts paid to
enter into these arrangements were insignificant. Based on LIBOR rates in
effect at March 31, 2000, this amounted to a net reduction in the
carrying cost of the Notes
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NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
from 9 1/2% to 6.13%, or 337 basis points. In addition, the swap
arrangement also effectively hedges the price at which these Notes can be
repurchased by the Company. For the three months ended March 31, 2000,
the Company recorded an unrealized loss of $781,000 related to the change
in the fair value of the Notes.
For 2000, the Company entered into swap contracts on 16,500 barrels of
oil per day ("BOPD"), at an average West Texas Intermediate ("WTI") price
of $17.94 per barrel. The Company also entered into collars on an
additional 16,500 BOPD, with a floor of $16.00 per barrel and ceiling of
$21.21 per barrel. This production is hedged based on a fixed NYMEX
price. 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 March 31, 2000, the market value of the hedge
positions was a loss of approximately $48.0 million. 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.
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, and for the third quarter on 20,000 BOPD at an average WTI price
of $21.22 per barrel. At March 31, 2000, the market value of these swaps
was a loss of $24.6 million. These agreements expose the Company to
counterparty credit risk to the extent that the counterparty is unable to
meet its settlement commitments to the Company.
RECENT ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities". This statement, as amended by SFAS No. 137, establishes
standards of accounting for and disclosures of derivative instruments and
hedging activities. This statement requires all derivative instruments to
be carried on the balance sheet at fair value and is effective for the
Company beginning January 1, 2001. The Company has not yet determined the
impact of this statement on its financial condition or results of
operations.
RECLASSIFICATIONS
Certain reclassifications of prior year amounts have been made to conform
to the current presentation.
2. PROPERTY AND EQUIPMENT
The Company utilizes the successful efforts method of accounting for its
investments in oil and gas properties. Under successful efforts, oil and
gas lease acquisition costs and intangible drilling costs associated with
exploration efforts that result in the discovery of proved reserves and
costs associated with development drilling, whether or not successful,
are capitalized when incurred. When a proved property is sold, ceases to
produce or is abandoned, a gain or loss is recognized. When an entire
interest in an unproved property is sold for cash or cash equivalent,
gain or loss is recognized, taking into consideration any recorded
impairment. When a partial interest in an unproved property is sold, the
amount received is treated as a reduction of the cost of the interest
retained.
Unproved leasehold costs are capitalized pending the results of
exploration efforts. Significant unproved leasehold costs are reviewed
periodically and a loss is recognized to the extent, if any, that the
cost of the property has been impaired. Exploration costs, including
geological and geophysical expenses, exploratory dry holes and delay
rentals, are charged to expense as incurred.
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9
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Costs of productive wells, development dry holes and productive leases
are capitalized and depleted on a unit-of-production basis over the life
of the remaining proved reserves. Capitalized drilling costs are depleted
on a unit-of-production basis over the life of the remaining proved
developed reserves. Estimated costs (net of salvage value) of
dismantlement, abandonment and site remediation are computed by the
Company's independent reserve engineers and are included when calculating
depreciation and depletion using the unit-of-production method.
The Company reviews proved oil and gas properties on a depletable unit
basis whenever events or circumstances indicate that the carrying value
of those assets may not be recoverable. For each depletable unit
determined to be impaired, an impairment loss equal to the difference
between the carrying value and the fair value of the depletable unit is
recognized. Fair value, on a depletable unit basis, is estimated to be
the value of the undiscounted expected future net revenues computed by
application of estimated future oil and gas prices, production and
expenses, as determined by management, to estimated future production of
oil and gas reserves over the economic life of the reserves. If the
carrying value exceeds the undiscounted future net revenues, an
impairment is recognized equal to the difference between the carrying
value and the discounted estimated future net revenues of that depletable
unit. The Company considers all proved reserves and commodity pricing
based on available market information in its estimate of future net
revenues.
3. DEFERRED TAX ASSETS
The Company has deferred tax assets, net of valuation allowances, of
$23.4 million and $24.0 million as of March 31, 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.
4. INDUSTRY SEGMENT INFORMATION
As of March 31, 2000, the Company's oil and gas exploration and
production operations were concentrated primarily in two geographic
regions: domestically, onshore and offshore California, and
internationally, offshore the Republic of Congo in West Africa (the
"Congo").
For the Three Months Ended March 31,
------------------------------------
2000 1999
---- ----
Sales to unaffiliated customers:
Oil and gas - Domestic................................... $59,549 $ 39,803
Oil and gas - International.............................. 11,180 3,661
------- --------
Total sales................................................... 70,729 43,464
Gain on sale of assets, net.............................. 140 81,699
Other revenues........................................... 626 1,480
------- --------
Total revenues................................................ $71,495 $126,643
======= ========
Operating profit before income taxes:
Oil and gas - Domestic (a)............................... $17,879 $ 71,936
Oil and gas - International.............................. 2,751 (1,963)
------- --------
20,630 69,973
Unallocated corporate expenses................................ 9,606 8,253
Interest expense.............................................. 8,290 7,999
Dividends on TECONS........................................... 1,653 1,653
------- --------
Income before income taxes............................... $ 1,081 $ 52,068
======= ========
Depreciation, depletion and amortization:
Oil and gas - Domestic................................... $13,705 $ 21,147
Oil and gas - International.............................. 2,169 1,798
Other.................................................... 367 375
------- --------
$16,241 $ 23,320
======= ========
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NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
(a) Includes an $80.3 million gain on sale of the East Texas gas
properties for the three months ended March 31, 1999.
5. LONG-TERM DEBT
Long-term debt consists of the following (amounts in thousands):
March 31, December 31,
2000 1999
---- ----
9 1/2% Senior Subordinated Notes due 2008.............................. $257,310 $257,310
9 1/2% Senior Subordinated Notes due 2006.............................. 2,417 2,440
Bank credit facility (a)............................................... 79,025 81,000
OPIC credit facility................................................... 375 750
-------- --------
Total debt..................................................... 339,127 341,500
Less: current maturities............................................... (375) (750)
-------- --------
Long-term debt......................................................... $338,752 $340,750
======== ========
(a) Nuevo's Restated Credit Agreement dated June 30, 1999, provides
for secured revolving credit availability of up to $400.0 million
(subject to a semi-annual borrowing base determination) from a
bank group led by Bank of America, N.A. and Morgan Guaranty Trust
Company of New York, until its expiration on April 1, 2003. In
October 1999 and April 2000, the borrowing base on the Company's
credit facility was determined to be $300.0 million. The Company
was in compliance with all covenants as of March 31, 2000, and
does not anticipate any issues of non-compliance arising in the
foreseeable future. At March 31, 2000, outstanding borrowings
under the revolving credit agreement were $71.0 million.
Accordingly, $229.0 million of committed revolving credit capacity
was unused and available at March 31, 2000. Additionally, Nuevo
had $8.0 million of outstanding borrowings under an uncommitted
line of credit.
In May 2000, the Company announced that it has reached an
agreement with a group of nine major U.S and international banks
to amend and restate its credit facility, in order to make
structural changes that increase the value of the facility to the
Company. This amendment is expected to be finalized in the second
quarter of 2000.
6. EARNINGS PER SHARE COMPUTATION
SFAS No. 128 requires a reconciliation of the numerator (income) and
denominator (shares) of the basic earnings per share ("EPS") computation
to the numerator and denominator of the diluted EPS computation. In the
three-month period ended March 31, 1999, there were no potential dilutive
common shares. The Company's reconciliation is as follows:
For the Three Months Ended March 31,
-------------------------------------------
2000 1999
----------------- -------------------
Income Shares Income Shares
------ ------ ------ ------
Earnings per Common share - Basic.................. $645 17,814 $31,342 19,840
Effect of dilutive securities:
Stock options...................................... -- 395 -- --
---- ------ ------- ------
Earnings per Common share - Diluted................ $645 18,209 $31,342 19,840
==== ====== ======= ======
7. CONTINGENCIES AND OTHER MATTERS
The Company has 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
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NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
al. in the 79th Judicial District Court of Brooks County, Texas. The
plaintiffs, based on pleadings and deposition testimony, allege: i)
underpayment of royalties and claim damages, on a gross basis, based on
the most recent estimate of $56.5 million, including interest; ii) that
their production was improperly commingled with gas produced from an
adjoining lease, resulting in damages, including interest based on the
most recent estimate of $40.8 million (gross); iii) failure to develop
claiming damages including interest based on the most recent estimate of
$106.3 million (gross); and iv) numerous other claims that may result in
unspecified damages. Nuevo's working interest in these properties is 20%.
The Company, along with the other defendants in this case, denies these
allegations and is vigorously contesting these claims. Management does
not believe that the final outcome of this matter will have a material
adverse impact on the Company's operating results, financial condition or
liquidity. As of March 31, 2000 and December 31, 1999, management
believes that the estimated ultimate resolution of this matter is
adequately reflected in the condensed consolidated financial statements.
The Company has been named as a defendant in certain other lawsuits
incidental to its business. Management does not believe that the outcome
of such litigation will have a material adverse impact on the Company's
operating results or financial condition. However, these actions and
claims in the aggregate seek substantial damages against the Company and
are subject to the inherent uncertainties present in any litigation. The
Company is defending itself vigorously in all such matters.
In March 1999, the Company discovered that a non-officer employee had
fraudulently authorized and diverted for personal use Company funds
totaling $5.9 million, $1.6 million in 1999 and the remainder in 1998,
that were intended for international exploration. The Board of Directors
engaged a Certified Fraud Examiner to conduct an in-depth review of the
fraudulent transactions. The investigation confirmed that only one
employee was involved in the matter and that all misappropriated funds
were identified. The Company has reviewed and, where appropriate,
strengthened its internal control procedures. The Company is attempting
to recoup the loss; however, there is no certainty that any of the funds
will be recovered.
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
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12
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
took place, if an entity is acquired in its entirety and that entity has
certain tax attributes, for example tax loss carryforwards from
operations in the Republic of Congo, the subsequent owners of that entity
can continue to utilize those losses without restriction. Pursuant to the
agreement, the Company and CMS may be liable to the seller for the
recapture of these tax losses utilized by the seller in years prior to
the acquisitions if certain triggering events occur. A triggering event
will not occur if a subsequent purchaser enters into certain agreements
specified in the consolidated return regulations intended to ensure that
such losses will not be claimed. The only time limit associated with the
occurrence of a triggering event relates to the utilization of a dual
consolidated loss in a foreign jurisdiction. A dual consolidated loss
that is utilized to offset income in a foreign jurisdiction is only
subject to recapture for 15 years following the year in which the dual
consolidated loss was incurred for US income tax purposes. The Company's
potential direct liability could be as much as $48.5 million if a
triggering event with respect to the Company occurs. Additionally, the
Company believes that CMS's liability (for which the Company would be
jointly liable with an indemnification right against CMS) could be as
much as $64.1 million. The Company does not expect a triggering event to
occur with respect to it or CMS and does not believe the agreement will
have a material adverse effect upon the Company.
8. CONTINGENT PAYMENT AND PRICE SHARING AGREEMENTS
In connection with the acquisition from Unocal in 1996 of the properties
located in California, the Company is obligated to make a contingent
payment for the years 1998 through 2004 if oil prices exceed thresholds
set forth in the agreement with Unocal. Any contingent payment will be
accounted for as a purchase price adjustment to oil and gas properties.
The contingent payment will equal 50% of the difference between the
actual average annual price received on a field-by-field basis (capped by
a maximum price) and a minimum price, less ad valorem and production
taxes, multiplied by the actual number of barrels of oil sold during the
respective year. The minimum price of $17.75 per Bbl under the agreement
(determined based on near month of delivery of WTI crude oil on the
NYMEX) is escalated at 3% per year and the maximum price of $21.75 per
Bbl on the NYMEX is escalated at 3% per year. Minimum and maximum prices
are reduced to reflect the field level price by subtracting a fixed
differential established for each field. The reduction was established at
approximately the differential between actual sales prices and NYMEX
prices in effect in 1995 ($4.34 per Bbl weighted average for all the
properties acquired from Unocal). The Company accumulates credits to
offset the contingent payment when prices are $.50 per Bbl or more below
the minimum price. The Company computes this calculation annually and had
accumulated $30.8 million in price credits as of December 31, 1999, which
will be used to reduce future amounts owed under the contingent payment.
The Company expects that it will still have an accumulated credit balance
at the end of 2000 to offset future payments under this agreement. A
continuation of higher than normal oil price realizations would, however,
trigger payments under this agreement beginning in March of 2002.
In connection with the acquisition of the Congo properties in 1995, the
Company entered into a price sharing agreement with the seller. Under the
terms of the agreement, if the average price received for the oil
production during the year is greater than the benchmark price
established by the agreement, then the Company is obligated to pay the
seller 50% of the difference between the benchmark price and the actual
price received, for all the barrels associated with this acquisition. The
benchmark price for 2000 is $15.19 per Bbl. The benchmark price increases
each year, based on the increase in the Consumer Price Index. For 2000,
the effect of this agreement is that Nuevo is entitled to receive the
pricing upside above $15.19 per Bbl on approximately 56% of its Congo
production.
The Company acquired a 12% working interest in the Point Pedernales oil
field from Unocal in 1994 and the remainder of its interest 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
barrel, 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 Point Pedernales production.
12
13
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
9. SUBSEQUENT EVENT
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 will record a net gain on sale of
approximately $740,000.
10. SHARE REPURCHASES
In August 1999, the Company implemented a share repurchase program,
pursuant to the Board of Directors' authorizations to repurchase up to a
total of 3,616,600 shares at times and at prices deemed attractive by
management. As of March 31, 2000, the Company has repurchased 2,610,600
shares of its common stock in open market transactions at an average
purchase price, including commissions, of $16.75 per share.
13
14
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
ITEM 2.
FORWARD LOOKING STATEMENTS
This document includes "forward looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended (the "Securities
Act"), and Section 21E of the Securities Exchange Act of 1934 ("Exchange
Act"). All statements other than statements of historical facts included
in this document, including without limitation, statements under
"Management's Discussion and Analysis of Financial Condition and Results
of Operations" regarding the Company's financial position, estimated
quantities and net present values of reserves, business strategy, plans
and objectives of management of the Company for future operations and
covenant compliance, are forward-looking statements. Although the Company
believes that the assumptions upon which such forward-looking statements
are based are reasonable, it can give no assurances that such assumptions
will prove to have been correct. Important factors that could cause
actual results to differ materially from the Company's expectations
("Cautionary Statements") are disclosed below and elsewhere in this
document and in the Company's Annual Report on Form 10-K and other
filings made with the Securities and Exchange Commission. All subsequent
written and oral forward-looking statements attributable to the Company
or persons acting on its behalf are expressly qualified by the Cautionary
Statements.
CAPITAL RESOURCES AND LIQUIDITY
Since inception, the Company has expanded its operations through a series
of disciplined, low-cost acquisitions of oil and gas properties and the
subsequent exploitation and development of these properties. The Company
has complemented these efforts with strategic divestitures and an
opportunistic exploration program, which provides exposure to prospects
that have the potential to add substantially to the growth of the
Company. The funding of these activities has historically been provided
by operating cash flows, bank financing, private and public placements of
debt and equity securities, property divestitures and joint ventures with
industry participants. Net cash provided by (used in) operating
activities was $18.6 million and $(10.4) million for the three months
ended March 31, 2000 and 1999, respectively. The Company invested $12.2
million and $15.6 million in oil and gas properties for the three months
ended March 31, 2000 and 1999, respectively.
The current borrowing base on the Company's credit facility is $300.0
million. At March 31, 2000, outstanding borrowings under the revolving
credit agreement were $71.0 million. Accordingly, $229.0 million of
committed revolving credit capacity was unused and available at March 31,
2000. Additionally, Nuevo had $8.0 million of outstanding borrowings
under an uncommitted line of credit. At March 31, 2000, the Company had a
working capital deficit of $2.1 million.
In May 2000, the Company announced that it has reached an agreement with
a group of nine major U.S. and international banks to amend and restate
its credit facility in order to make structural changes that increase the
value of the facility to the Company. The banks, led by Bank of America,
agreed to an amended facility with a face amount of $410 million. The
amount can be expanded at Nuevo's option to an amount not to exceed $800
million, with increased commitments from existing banks, or with new
commitments from additional banks. Concurrently, the bank group approved
a $300.0 million borrowing base governing the availability under this new
bank facility through October 2000. 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. The adjustments to the agreement include adding two years to
the current three-year term, relaxing certain limitations on restricted
payments, streamlining the borrowing base determination process and
simplifying the administration of the facility with fewer banks.
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
The Company anticipates spending an additional $96.0 million on
development activities and an additional $28.0 million on exploration
activities and other capital projects during the remainder of the year.
14
15
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
Exploration and development expenditures, including amounts expensed
under the successful efforts method, for the first three months of 2000
and 1999 are as follows (amounts in thousands):
For the Three Months Ended
March 31,
--------------------------
2000 1999
---- ----
Domestic $12,400 $ 5,838
International 3,506 10,580
------- -------
Total $15,906 $16,418
======= =======
The following is a description of significant exploration and development
activity during the first three months of 2000.
Exploration Activity
Domestic
There was no significant activity during the first quarter of 2000.
International
On February 16, 2000, the Company completed its acquisition of the 3-D
seismic survey across the Eastern portion of its Accra-Keta concession
offshore the Republic of Ghana in West Africa ("Ghana"). The Company's
costs of the 3-D seismic survey acquisition and processing were
approximately $3.0 million. This survey extends from the outer shelf,
across the slope, and into the deepwater regions of the block. The
Company is currently interpreting the data, which is expected to be
complete by the end of the second quarter. The Company currently plans to
drill its first exploratory well on the concession late this year.
Estimated costs to drill this well are approximately $12.5 million, on a
gross basis.
Development Activity
Domestic
The Company drilled a total of 50 development wells in the first quarter
of 2000, most of which relate to the interests acquired from Texaco in
1999. The Company completed the first phase of its development drilling
program on its Cymric lease acquired from Texaco. This first phase
included drilling 40 wells, all of which are currently producing at a
combined rate of 3,200 barrels of oil per day ("BOPD"). The Company plans
to begin the second phase of this development program in June 2000, which
includes drilling an additional 60 wells. The Company expects this
program to be completed by the end of the year. In addition to the
development activity at Cymric, the Company successfully drilled two
offshore wells at its Huntington Beach property. These two wells should
be completed and placed in production in the second quarter of 2000.
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 first quarter of 2000, the Company
completed the installation of its first cogeneration unit, which utilizes
the gas and converts it to electricity to supply all of the field
electrical needs as well as provides excess electricity for sale. The
completion of the cogeneration project cost approximately $4.5 million
and should result in significant cost savings of approximately $450,000
per year plus an additional $1.7 million per year in electricity sales
for the Brea Olinda property. Also, the Company is currently beginning
construction of a water plant at its Cymric Field that will provide a
long-term source of water to be used in the Company's steam operations
and help reduce expenses in the long-term. The water plant is expected to
cost approximately $6.2 million to construct.
International
There was no significant activity during the first quarter of 2000.
15
16
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
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 is sold.
There were no such deferred gains or losses at March 31, 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
$26.5 million and increased by $0.2 million in the first quarter of 2000
and 1999, respectively.
On February 26, 1999, the Company entered into a swap arrangement with a
major financial institution that effectively converts the interest rate
on $16.4 million notional amount of the 9 1/2% Senior Subordinated Notes
due 2008 ("Notes") to a variable LIBOR-based rate. On February 25, 2000,
this arrangement was extended through February 26, 2001. Amounts paid to
enter into these arrangements were insignificant. Based on LIBOR rates in
effect at March 31, 2000, this amounted to a net reduction in the
carrying cost of the Notes from 9 1/2% to 6.13%, or 337 basis points. In
addition, the swap arrangement also effectively hedges the price at which
these Notes can be repurchased by the Company. For the three months ended
March 31, 2000, the Company recorded an unrealized loss of $781,000
related to the change in the fair value of the Notes.
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 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. 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 March
31, 2000, the market value of the hedge positions was a loss of
approximately $48.0 million. 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.
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, and for the third quarter on 20,000 BOPD at an average WTI price
of $21.22 per barrel. At March 31, 2000, the market value of these swaps
was a loss of $24.6 million. These agreements expose the Company to
16
17
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
counterparty credit risk to the extent that the counterparty is unable to
meet its settlement commitments to the Company.
CONTINGENT PAYMENT AND PRICE SHARING AGREEMENTS
In connection with the acquisition from Unocal in 1996 of the properties
located in California, the Company is obligated to make a contingent
payment for the years 1998 through 2004 if oil prices exceed thresholds
set forth in the agreement with Unocal. Any contingent payment will be
accounted for as a purchase price adjustment to oil and gas properties.
The contingent payment will equal 50% of the difference between the
actual average annual price received on a field-by-field basis (capped by
a maximum price) and a minimum price, less ad valorem and production
taxes, multiplied by the actual number of barrels of oil sold during the
respective year. The minimum price of $17.75 per Bbl under the agreement
(determined based on near month of delivery of WTI crude oil on the
NYMEX) is escalated at 3% per year and the maximum price of $21.75 per
Bbl on the NYMEX is escalated at 3% per year. Minimum and maximum prices
are reduced to reflect the field level price by subtracting a fixed
differential established for each field. The reduction was established at
approximately the differential between actual sales prices and NYMEX
prices in effect in 1995 ($4.34 per Bbl weighted average for all the
properties acquired from Unocal). The Company accumulates credits to
offset the contingent payment when prices are $.50 per Bbl or more below
the minimum price. The Company computes this calculation annually and had
accumulated $30.8 million in price credits as of December 31, 1999, which
will be used to reduce future amounts owed under the contingent payment.
The Company expects that it will still have an accumulated credit balance
at the end of 2000 to offset future payments under this agreement. A
continuation of higher than normal oil price realizations would, however,
trigger payments under this agreement beginning in March of 2002.
In connection with the acquisition of the Congo properties in 1995, the
Company entered into a price sharing agreement with the seller. Under the
terms of the agreement, if the average price received for the oil
production during the year is greater than the benchmark price
established by the agreement, then the Company is obligated to pay the
seller 50% of the difference between the benchmark price and the actual
price received, for all the barrels associated with this acquisition. The
benchmark price for 2000 is $15.19 per Bbl. The benchmark price increases
each year, based on the increase in the Consumer Price Index. For 2000,
the effect of this agreement is that Nuevo is entitled to receive the
pricing upside above $15.19 per Bbl on approximately 56% of its Congo
production.
The Company acquired a 12% working interest in the Point Pedernales oil
field from Unocal in 1994 and the remainder of its interest 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
barrel, 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 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, establishes
standards of accounting for and disclosures of derivative instruments and
hedging activities. This statement requires all derivative instruments to
be carried on the balance sheet at fair value and is effective for the
Company beginning January 1, 2001. The Company has not yet determined the
impact of this statement on its financial condition or results of
operations.
17
18
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
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 March 31, 2000, the Company has repurchased 2,610,600
shares of its common stock in open market transactions at an average
purchase price, including commissions, of $16.75 per share.
DEFERRED INCOME TAXES
The Company has deferred tax assets, net of valuation allowances, of
$23.4 million and $24.0 million as of March 31, 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.
YEAR 2000
In 1998, the Company and its outside service provider, Torch Energy
Advisers Incorporated ("Torch"), jointly developed a plan to address
Nuevo's risks associated with the Year 2000 issues ("Y2K.") The plan
grouped the risks associated with Y2K into three general areas: i)
financial and administrative systems, ii) embedded systems in field
process control units, and iii) third party exposures. The Company did
not encounter any critical financial and administrative system or
embedded system failures during the date roll over to the Year 2000, and
has not experienced any disruptions of business activities as a result of
Y2K failures encountered by third parties (customers, suppliers and
service providers.) To date, the Company has not incurred, and does not
expect to incur, any material expenditures in connection with
identifying, assessing or remediating Y2K compliance issues.
18
19
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
RESULTS OF OPERATIONS (THREE MONTHS ENDED MARCH 31, 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 March 31, %
---------------- Increase/
2000 1999 (Decrease)
---- ---- ----------
Production:
Oil and condensate - Domestic (MBBLS)..................... 3,714 3,985 (7)%
Oil and condensate - International (MBBLS)................ 501 389 29%
------ ------
Oil and condensate - Total (MBBLS)........................ 4,215 4,374 (4)%
Natural gas - Domestic/Total (MMCF)....................... 3,995 4,092 (2)%
Natural gas liquids - Domestic/Total (MBBLS).............. 41 43 (5)%
Equivalent barrels of production - Domestic (MBOE)........ 4,421 4,710 (6)%
Equivalent barrels of production - International (MBOE)... 501 389 29%
------ ------
Equivalent barrels of production - Total (MBOE)........... 4,922 5,099 (3)%
Average Sales Price:
Oil and condensate - Domestic............................. $13.13 $ 7.84 67%
Oil and condensate - International........................ $22.32 $ 9.46 136%
Oil and condensate - Total................................ $14.22 $ 7.99 78%
Natural gas - Domestic/Total.............................. $ 2.42 $ 1.83 32%
Lease Operating Expense:
Average unit production cost(1) per BOE - Domestic........ $ 6.28 $ 5.72 10%
Average unit production cost(1) per BOE - International... $ 6.69 $ 7.64 (12)%
Average unit production cost(1) per BOE - Total........... $ 6.32 $ 5.87 8%
(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 March 31, 2000, were $70.7
million, or 63% higher than oil and gas revenues for the same period in 1999.
This increase is primarily due to a 78% increase in realized oil prices and a
32% increase in realized gas prices. These increases were partially offset by a
decrease in production, which was primarily attributable to less capital
spending in 1999. First quarter 2000 oil price realizations reflect hedging
losses of $26.5 million, or $6.29 per barrel.
Domestic: Oil and gas revenues for the three months ended March 31, 2000, were
50% higher than oil and gas revenues for the same period in 1999. This increase
is primarily due to a 67% improvement in average realized oil prices and a 32%
improvement in average realized gas prices, partially offset by a 6% decrease in
total production as a result of reduced capital spending in 1999. The realized
oil price of $13.13 per barrel for the first quarter of 2000 includes negative
hedging results of $7.50 per barrel of oil.
19
20
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
International: Oil revenues for the three months ended March 31, 2000, more than
tripled as compared to the same period in 1999. This significant increase
resulted from a 136% increase in oil price realizations to $22.32 per barrel,
coupled with a 29% increase in oil production. The realized oil price for the
first quarter of 2000 includes hedging gains of $2.70 per barrel of oil,
compared to hedging gains of $0.49 per barrel in the first quarter of 1999.
Gain on Sale of Assets, net:
Gain on sale of assets for the three months ended March 31, 2000, was $140,000,
representing positive revisions for accounting adjustments in connection with
the Company's sale of certain oil and gas properties in 1999. Gain on sale of
assets for the three months ended March 31, 1999, was $81.7 million, resulting
from the Company's sale of its East Texas natural gas properties in January
1999.
Interest and Other Income:
Interest and other income for the three months ended March 31, 2000, is
comprised of several individually insignificant items. Interest and other income
for the three months ended March 31, 1999, includes $1.3 million associated with
interest earned on an escrow account for the $100.0 million representing a
portion of the proceeds from the sale of the East Texas natural gas properties,
as well as several individually insignificant items.
Expenses
Lease Operating Expenses:
Lease operating expenses for the three months ended March 31, 2000, were $31.1
million, or 4% higher than for the three months ended March 31, 1999. Lease
operating expenses per barrel of oil equivalent were $6.32 in the first quarter
of 2000, compared to $5.87 in the same period in 1999. The per barrel increase
is primarily due to the 3% decrease in total production, an increase in steam
and workover costs, and a change in asset mix resulting from the June 1999
purchase of the Texaco properties, which have relatively higher operating costs.
Domestic: Lease operating expenses per barrel of oil equivalent ("BOE") were
$6.28 in the first quarter of 2000, compared to $5.72 in the same period in
1999. Decreased production and higher steam and workover costs contributed to
the higher lease operating expenses quarter over quarter.
International: Lease operating expenses per BOE were $6.69 in the first quarter
of 2000, compared to $7.64 in the same period in 1999. The decrease in lease
operating expenses per BOE is primarily attributable to the 29% increase in
production.
Exploration Costs:
Exploration costs, including geological and geophysical ("G&G") costs, dry hole
costs, delay rentals and expensed project costs, were $3.3 million and $2.1
million for the three months ended March 31, 2000 and 1999, respectively. For
the three months ended March 31, 2000, exploration costs were comprised of $3.2
million in G&G (primarily for 3-D seismic acquisition and processing in the
Accra-Keta prospect offshore Ghana), and $0.1 million in delay rentals. For the
three months ended March 31, 1999, exploration costs were comprised of $0.8
million of dry hole costs, $0.8 million in G&G, $0.2 million in delay rentals
and $0.3 million of other project costs.
Depreciation, Depletion and Amortization:
Depreciation, depletion and amortization for the three months ended March 31,
2000, reflects a 30% decrease from the same period in 1999, due to a lower
depletion rate, which primarily resulted from a significant increase in reserve
estimates at year-end 1999 versus year-end 1998.
20
21
NUEVO ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
General and Administrative Expenses:
General and administrative expenses were $5.4 million and $3.8 million in the
three months ended March 31, 2000 and 1999, respectively. The 40% increase is
due primarily to a $0.7 million increase in bonus accruals, as bonuses were not
projected or accrued in the first quarter of 1999 and a $0.3 million increase in
the fair market value of securities in the Company's deferred compensation plan.
The remaining increase is made up of individually insignificant items.
Interest Expense:
Interest expense of $8.3 million for the three months ended March 31, 2000,
increased 4% as compared to interest expense in the same period in 1999. The
increase is primarily attributable to higher interest rates as the Company
exchanged its 8 7/8% Senior Subordinated Notes for 9 -1/2% Senior Subordinated
Notes due 2008 in the third quarter of 1999.
Other Expense:
The 54% decrease in other expense from the first quarter of 1999 to the first
quarter of 2000 is primarily due to fraud charges incurred in the first quarter
of 1999. 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. This decrease was
partially offset by a negative mark to market adjustment of $781,000 related to
the Company's liability management swap (see Note 1 to the Notes to Condensed
Consolidated Financial Statements) in the first quarter of 2000.
Net Income
Net income of $645,000 million, $0.04 per common share - basic and diluted, was
reported for the three months ended March 31, 2000, as compared to net income of
$31.3 million, $1.58 per common share - basic and diluted, reported for the same
period in 1999.
21
22
NUEVO ENERGY COMPANY
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 3.
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.
22
23
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
27. Financial Data Schedule
(b) REPORTS ON FORM 8-K.
1) A Current Report on Form 8-K, dated February 23, 2000, reporting
Item 5. Other Events and Item 7. Financial Statements and Exhibits
were filed on February 23, 2000.
2) A Current Report on Form 8-K, dated February 4, 2000, reporting
Item 5. Other Events and Item 7. Financial Statements and Exhibits
were filed on March 6, 2000.
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GLOSSARY OF OIL AND GAS TERMS
TERMS USED TO DESCRIBE QUANTITIES OF OIL AND NATURAL GAS
- Bbl -- One stock tank barrel, or 42 US gallons liquid volume, of
crude oil or other liquid hydrocarbons.
- Bcf -- One billion cubic feet of natural gas.
- Bcfe -- One billion cubic feet of natural gas equivalent.
- BOE -- One barrel of oil equivalent, converting gas to oil at the
ratio of 6 Mcf of gas to 1 Bbl of oil.
- MBbl -- One thousand Bbls.
- Mcf -- One thousand cubic feet of natural gas.
- MMBbl -- One million Bbls of oil or other liquid hydrocarbons.
- MMcf -- One million cubic feet of natural gas.
- MBOE -- One thousand BOE.
- MMBOE -- One million BOE.
TERMS USED TO CLASSIFY OUR RESERVE QUANTITIES
- Proved reserves -- The estimated quantities of crude oil,
natural gas and natural gas liquids which, upon analysis of
geological and engineering data, appear with reasonable certainty
to be recoverable in the future from known oil and natural gas
reservoirs under existing economic and operating conditions.
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.
- Proved developed reserves -- Proved reserves that can be
expected to be recovered through existing wells with existing
equipment and operating methods.
- Proved undeveloped reserves -- Proved reserves that are
expected to be recovered from new wells on undrilled acreage, or
from existing wells where a relatively major expenditure is
required.
TERMS USED TO DESCRIBE THE LEGAL OWNERSHIP OF THE COMPANY'S OIL AND GAS
PROPERTIES
- Royalty interest -- A real property interest entitling the owner
to receive a specified portion of the gross proceeds of the sale
of oil and natural gas production or, if the conveyance creating
the interest provides, a specific portion of oil and natural gas
produced, without any deduction for the costs to explore for,
develop or produce the oil and natural gas. A royalty interest
owner has no right to consent to or approve the operation and
development of the property, while the owners of the working
interests have the exclusive right to exploit the mineral on the
land.
- Working interest -- A real property interest entitling the owner
to receive a specified percentage of the proceeds of the sale of
oil and natural gas production or a percentage of the production,
but requiring the owner of the working interest to bear the cost
to explore for, develop and produce such oil and natural gas. A
working interest owner who owns a portion of the working interest
may participate either as operator or by voting his percentage
interest to approve or disapprove the appointment of an operator
and drilling and other major activities in connection with the
development and operation of a property.
TERMS USED TO DESCRIBE SEISMIC OPERATIONS
- Seismic data -- Oil and gas companies use seismic data as their
principal source of information to locate oil and gas deposits,
both to aid in exploration for new deposits and to manage or
enhance production from known reservoirs. To gather seismic data,
an energy source is used to send sound waves into the subsurface
strata. These waves are reflected back to the surface by
underground formations, where they are detected by geophones which
digitize and record the reflected waves. Computers are then used
to process the raw data to develop an image of underground
formations.
- 2-D seismic data -- 2-D seismic survey data has been the
standard acquisition technique used to image geologic formations
over a broad area. 2-D seismic data is collected by a single line
of energy sources which reflect seismic waves to a single line of
geophones. When processed, 2-D seismic data produces an image of a
single vertical plane of sub-surface data.
- 3-D seismic -- 3-D seismic data is collected using a grid of
energy sources, which are generally spread over several miles. A
3-D survey produces a three dimensional image of the subsurface
geology by collecting seismic data along parallel lines and
creating a cube of information that can be divided into various
planes, thus improving visualization. Consequently, 3-D seismic
data is a more reliable indicator of potential oil and natural gas
reservoirs in the area evaluated.
THE COMPANY'S MISCELLANEOUS DEFINITIONS
- Infill drilling - Infill drilling is the drilling of an
additional well or additional wells in excess of those provided
for by a spacing order in order to more adequately drain a
reservoir.
- No. 6 fuel oil (Bunker) - No. 6 fuel oil is a heavy residual
fuel oil used by ships, industry, and for large-scale heating
installations.
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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: May 15, 2000 By:/s/ Douglas L. Foshee
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Douglas L. Foshee
Chairman, President and
Chief Executive Officer
Date: May 15, 2000 By:/s/ Robert M. King
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Robert M. King
Senior Vice President and
Chief Financial Officer
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