================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM _____________________ TO _______________________
COMMISSION FILE NUMBER 1-10537
NUEVO ENERGY COMPANY
(Exact Name of Registrant as Specified in Its Charter)
DELAWARE 76-0304436
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
1021 MAIN, SUITE 2100, HOUSTON, TEXAS 77002
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (713) 652-0706
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days Yes [X] No[ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes [X] No [ ]
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date.
Common Stock, par value $.01 per share.
Shares outstanding on May 8, 2003: 19,247,269.
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NUEVO ENERGY COMPANY
TABLE OF CONTENTS
PAGE
----
PART I
Item 1. Financial Statements
Condensed Consolidated Statements of Income........................ 3
Condensed Consolidated Balance Sheets.............................. 4
Condensed Consolidated Statements of Cash Flows.................... 5
Condensed Consolidated Statements of Comprehensive Income (Loss)... 6
Notes to the Condensed Consolidated Financial Statements........... 7
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations.......................................... 15
Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation Reform Act of 1995. 21
Item 3. Quantitative and Qualitative Disclosures About Market Risk............ 22
Item 4 Disclosure Controls and Procedures.................................... 23
PART II
Item 1. Legal Proceedings..................................................... 24
Item 2. Changes in Securities and Use of Proceeds............................. 24
Item 3. Defaults Upon Senior Securities....................................... 24
Item 4. Submission of Matters to a Vote of Security-Holders................... 24
Item 5. Other Information..................................................... 24
Item 6. Exhibits and Reports on Form 8-K...................................... 24
Signatures ........................................................... 25
Certifications........................................................ 26
2
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE DATA)
(UNAUDITED)
Quarter Ended March 31,
-----------------------
2003 2002
-------- --------
Revenues
Crude oil and liquids ............................................. $ 82,802 $ 65,251
Natural gas ....................................................... 15,310 5,711
Other ............................................................. 138 6
-------- --------
98,250 70,968
-------- --------
Costs and Expenses
Lease operating expenses .......................................... 39,330 34,626
Exploration costs ................................................. 1,072 1,058
Depreciation, depletion, amortization and accretion ............... 17,389 17,248
General and administrative expenses ............................... 6,717 6,083
Other ............................................................. 795 24
-------- --------
65,303 59,039
-------- --------
Operating Income ....................................................... 32,947 11,929
Derivative gain (loss) ............................................ (943) (756)
Interest income ................................................... 79 108
Interest expense .................................................. (9,322) (9,004)
Dividends on TECONS ............................................... (1,653) (1,653)
-------- --------
Income From Continuing Operations Before Income Taxes .................. 21,108 624
Income Tax Expense
Current ........................................................... 1,504 --
Deferred .......................................................... 6,941 251
-------- --------
8,445 251
-------- --------
Income From Continuing Operations ...................................... 12,663 373
Income from discontinued operations, including gain/loss on disposal,
net of income taxes ................................................. 4,554 1,089
Cumulative effect of a change in accounting principle, net of income tax
8,496 --
-------- --------
Net Income ............................................................. $ 25,713 $ 1,462
======== ========
Earnings Per Share:
Basic
Income from continuing operations ................................. $ 0.66 $ 0.02
Income from discontinued operations, net of income taxes .......... 0.24 0.07
Cumulative effect of a change in accounting principle, net of
income tax benefit ............................................. 0.44 --
-------- --------
Net income ........................................................ $ 1.34 $ 0.09
======== ========
Diluted
Income from continuing operations ................................. $ 0.65 $ 0.01
Income from discontinued operations, net of income taxes .......... 0.24 0.07
Cumulative effect of a change in accounting principle, net of
income tax benefit ........................................... 0.44 --
-------- --------
Net income ........................................................ $ 1.33 $ 0.08
======== ========
Weighted Average Shares Outstanding:
Basic ............................................................. 19,199 17,000
======== ========
Diluted ........................................................... 19,305 17,176
======== ========
See accompanying notes.
3
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)
March 31, December 31,
2003 2002
----------- -----------
(UNAUDITED)
ASSETS
Current assets
Cash and cash equivalents ........................................................ $ 73,843 $ 5,047
Accounts receivable, net ......................................................... 60,017 40,945
Inventory ........................................................................ 6,180 7,326
Assets held for sale ............................................................. 48,438 92,738
Deferred income taxes ............................................................ 8,835 7,683
Prepaid expenses and other ....................................................... 2,164 3,862
----------- -----------
Total current assets ......................................................... 199,477 157,601
----------- -----------
Property and equipment, at cost
Land ............................................................................. 5,224 5,224
Oil and gas properties (successful efforts method) ............................... 989,286 951,258
Other property ................................................................... 14,411 14,303
----------- -----------
1,008,921 970,785
Accumulated depreciation, depletion and amortization ............................. (311,662) (357,072)
----------- -----------
Total property and equipment, net ............................................ 697,259 613,713
----------- -----------
Deferred income taxes ................................................................ 29,164 43,258
Goodwill ............................................................................. 19,664 19,664
Other assets ......................................................................... 23,569 20,935
----------- -----------
Total assets .............................................................. $ 969,133 $ 855,171
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable ................................................................. $ 31,114 $ 34,323
Accrued interest ................................................................. 14,431 5,169
Accrued drilling costs ........................................................... 6,802 8,035
Accrued lease operating costs .................................................... 16,840 15,598
Price risk management activities ................................................. 28,234 20,884
Other accrued liabilities ........................................................ 29,829 16,735
Current portion of long-term debt ................................................ 2,367 --
----------- -----------
Total current liabilities .................................................... 129,617 100,744
----------- -----------
Long-Term debt
Senior Subordinated Notes ........................................................ 407,210 409,577
Bank Credit Facility ............................................................. -- 28,700
----------- -----------
Total debt ................................................................... 407,210 438,277
Interest rate swaps - fair value adjustment ...................................... 2,392 2,161
Interest rate swaps - termination gain ........................................... 11,383 11,673
----------- -----------
Long-term debt ............................................................... 420,985 452,111
----------- -----------
Asset retirement obligation .......................................................... 91,774 --
Other long-term liabilities .......................................................... 14,788 13,040
Company-Obligated Mandatorily Redeemable Convertible Preferred Securities of Nuevo
Financing I (TECONS) ............................................................. 115,000 115,000
Commitments and contingencies (Note 9)
Stockholders' equity
Preferred stock, $1.00 par value, 10,000,000 shares authorized; 7% Cumulative
Convertible Preferred Stock, none issued ....................................... -- --
Common stock, $0.01 par value, 50,000,000 shares authorized, 23,073,151 and
23,048,388 shares issued and 19,225,514 and 19,110,102 shares outstanding, ..... 231 230
respectively
Additional paid-in capital ....................................................... 389,949 388,479
Treasury stock, at cost, 3,847,639 and 3,867,691 shares, respectively ............ (75,414) (75,683)
Deferred stock compensation and other ............................................ (1,708) (605)
Accumulated other comprehensive income (loss) .................................... (15,124) (11,468)
Accumulated deficit .............................................................. (100,965) (126,677)
----------- -----------
Total stockholders' equity ................................................... 196,969 174,276
----------- -----------
Total liabilities and stockholders' equity ................................ $ 969,133 $ 855,171
=========== ===========
See accompanying notes.
4
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
Quarter Ended March 31,
-----------------------
2003 2002
-------- --------
Cash flows from operating activities
Net income .................................................. $ 25,713 $ 1,462
Adjustments to reconcile net income to net cash provided by
operating activities
Depreciation, depletion, amortization and accretion .... 17,389 17,248
Dry hole costs ......................................... 571 90
Amortization of debt financing costs ................... 633 602
Deferred income taxes .................................. 6,941 251
Non-cash effect of discontinued operations ............. 33 2,637
Cumulative effect of a change in accounting principle .. (8,496) --
Other .................................................. 1,560 797
Working capital changes, net of non-cash transactions
Accounts receivable .................................... (18,896) 3,765
Accounts payable ....................................... (2,071) (7,813)
Accrued liabilities .................................... 6,947 1,000
Other .................................................. 16,810 (409)
-------- --------
Net cash provided by operating activities ......... 47,134 19,630
-------- --------
Cash flows from investing activities
Additions to oil and gas properties ......................... (16,213) (22,662)
Additions to other properties ............................... (672) (1,013)
Proceeds from sale of properties ............................ 65,406 --
Other investing activities .................................. 1,841 --
-------- --------
Net cash provided by (used) in investing activities 50,362 (23,675)
-------- --------
Cash flows from financing activities
Net repayments of credit facility ........................... (28,700) (1,525)
Proceeds from exercise of stock options ..................... -- 759
-------- --------
Net cash used in financing activities ............. (28,700) (766)
-------- --------
Increase (decrease) in cash and cash equivalents ............... 68,796 (4,811)
Cash and cash equivalents
Beginning of period ........................................ 5,047 7,110
-------- --------
End of period .............................................. $ 73,843 $ 2,299
======== ========
See accompanying notes.
5
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(IN THOUSANDS)
(UNAUDITED)
Quarter Ended March 31,
-----------------------
2003 2002
-------- --------
Net income ................................................................ $ 25,713 $ 1,462
Unrealized gains (losses) from cash flow hedging activity:
Reclassification of initial cumulative effect transition adjustment at
original value .................................................... -- (1,662)
Reclassification adjustments of settled contracts .................... 9,280 (1,134)
Changes in fair value of derivative instruments during the period ... (12,936) (11,710)
-------- --------
Other comprehensive income (loss) ............................ (3,656) (14,506)
-------- --------
Comprehensive income (loss) ............................................. $ 22,057 $(13,044)
======== ========
See accompanying notes.
6
NUEVO ENERGY COMPANY
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION
Our 2002 Annual Report on Form 10-K includes a summary of our significant
accounting policies and other disclosures. You should read it in conjunction
with this Quarterly Report on Form 10-Q. The financial statements as of March
31, 2003, and for the quarters ended March 31, 2003 and 2002, are unaudited. The
balance sheet as of December 31, 2002, is derived from the audited balance sheet
filed in the Form 10-K. These financial statements have been prepared pursuant
to the rules and regulations of the U.S. Securities and Exchange Commission and
do not include all disclosures required on an annual basis by accounting
principles generally accepted in the United States. In our opinion, we have made
all adjustments, all of which are of a normal, recurring nature, to fairly
present our interim period results. Information for interim periods may not
necessarily indicate the results of operations for the entire year. The prior
period information also includes reclassifications which were made to conform to
the current period presentation. These reclassifications have no effect on our
reported net income, cash flows or stockholders' equity.
Our accounting policies are consistent with those discussed in our Form
10-K, except as discussed below. You should refer to our Form 10-K for a further
discussion of those policies.
Amendment of Statement 133 on Derivative Instruments and Hedging Activities.
In April 2003, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 149, Amendment of
Statement 133 on Derivative Instruments and Hedging Activities. The statement
amends and clarifies accounting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities
under SFAS No. 133. Except for implementation issues that have been effective
for fiscal quarters that began prior to June 15, 2003 and should continue to be
applied in accordance with their effective dates, this statement is effective
for contracts entered into or modified after June 30, 2003 and for hedging
relationships designated after June 30, 2003. The financial statement provisions
are effective prospectively, except for forward purchases or sales of
when-issued securities or other securities that do not yet exist and in which
case SFAS No. 149 should be applied to both existing contracts and new contracts
entered into after June 30, 2003. We are currently evaluating the effects of
this pronouncement.
Accounting for Asset Retirement Obligations.
In August 2001, the FASB issued SFAS No. 143, Accounting for Asset
Retirement Obligations. This Statement requires a liability to be recorded
relating to the eventual retirement and removal of assets used in our business.
The liability is discounted to its present value, with a corresponding increase
to the related asset value. Over the life of the asset, the liability will be
accreted to its future value and eventually extinguished when the asset is taken
out of service. The provisions of this Statement are effective for fiscal years
beginning after June 15, 2002. We adopted the provisions of SFAS No. 143 on
January 1, 2003 to record our asset retirement obligation to plug and abandon
oil and gas wells. In connection with the initial application of SFAS No. 143,
we recorded a cumulative effect of change in accounting principle, net of taxes,
of $8.5 million as an increase to net income. In addition, we recorded an asset
retirement obligation for oil and gas properties and equipment of $87.8 million.
The following table summarizes asset retirement obligation transactions recorded
in accordance with the provisions of SFAS No. 143:
Quarter Ended
March 31, 2003
--------------
(In thousands)
Beginning asset retirement obligation............ $ 87,828
Liabilities incurred during period............... 2,304
Liabilities settled during period................ (481)
Accretion expense................................ 2,123
--------------
Ending asset retirement obligation............... $ 91,774
==============
7
The following table summarizes the pro forma basis as required by SFAS No.
143, had we adopted the provisions of SFAS No. 143 prior to January 1, 2003, the
amount of the asset retirement obligations would have been as follows:
Pro Forma
Asset Retirement
Adoption Date Obligation
------------- ----------------
(In thousands)
January 1, 2000................. $ 65,621
December 31, 2000............... 72,706
December 31, 2001............... 80,062
March 31, 2002.................. 81,687
December 31, 2002............... 87,828
In addition, pro forma net income and earnings per share for the three
months ended March 31, 2002 and for the years ended December 31, 2002, 2001 and
2000 for the change in accounting had it been implemented during the periods:
1st Qtr
2002 2002 2001 2000
---------- ---------- ---------- ----------
(In thousands, except per share data)
Net income
As Reported ............... $ 1,462 $ 12,275 $ (79,171) $ 11,635
Pro Forma ................. 2,750 14,897 (75,479) 11,624
Net income per share - Reported
Basic ..................... 0.09 0.70 (4.73) 0.67
Diluted ................... 0.08 0.69 (4.73) 0.64
Net income per share - Pro Forma
Basic ..................... 0.16 0.84 (4.51) 0.67
Diluted ................... 0.16 0.84 (4.51) 0.65
Guarantor's Accounting and Disclosure Requirements.
In November 2002, the FASB issued Interpretation No. 45 ("FIN 45"),
Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of the Indebtedness of Others, which clarifies the
requirements of SFAS No. 5, Accounting for Contingencies, relating to a
guarantor's accounting for and disclosures of certain guarantees issued. FIN 45
requires enhanced disclosures for certain guarantees. It also will require
certain guarantees that are issued or modified after December 31, 2002,
including certain third-party guarantees, to be initially recorded on the
balance sheet at fair value. For guarantees issued on or before December 3,
2002, liabilities are recorded when and if payments become probable and
estimable. The financial statement recognition provisions are effective
prospectively, and we cannot reasonably estimate the impact of FIN 45 until
guarantees are issued or modified in future periods, at which time their results
will be initially reported in the financial statements.
Consolidation of Variable Interest Entities.
In January 2003, the FASB issued Interpretation No. 46 ("FIN 46"),
Consolidation of Variable Interest Entities, an interpretation of Accounting
Research Bulletin No. 51. FIN 46 requires certain variable interest entities, or
VIEs, to be consolidated by the primary beneficiary of the entity if the equity
investors in the entity do not have the characteristics of a controlling
financial interest or do not have sufficient equity at risk for the entity to
finance its activities without additional subordinated financial support from
other parties. FIN 46 is effective for all VIEs created or acquired after
January 31, 2003. For VIEs created or acquired prior to February 1, 2003, the
provisions of FIN 46 must be applied for the first interim or annual period
beginning after June 15, 2003. We currently have no contractual relationship or
other business relationship with a variable interest entity and therefore the
adoption of FIN 46 will have no effect on our consolidated financial position,
results of operations or cash flows.
8
2. STOCK-BASED COMPENSATION
We account for stock compensation plans under the intrinsic value method
of Accounting Principles Board Opinion ("APB") No. 25, Accounting for Stock
Issued to Employees. No compensation expense is recognized for stock options
that had an exercise price equal to their market value of the underlying common
stock on the date of grant. As permitted by SFAS No. 123, Accounting for
Stock-Based Compensation, we have continued to apply APB Opinion No. 25 for
purposes of determining net income. Had compensation expense for stock-based
compensation been determined based on the fair value at the date of grant, our
net income and earnings per share would have been as follows:
Quarter Ended March 31,
------------------------
2003 2002
---------- ----------
(In thousands, except per share data)
Net income as reported ................................................... $ 25,713 $ 1,462
Add:
Stock based employee compensation expense included in
reported net income, net of related income tax ...................... 178 152
Deduct:
Total stock based employee compensation expense determined under fair
value based method for all awards, net of related income tax ........ (225) (1,113)
---------- ----------
Pro forma net income ..................................................... $ 25,666 $ 501
========== ==========
Earnings per share:
Basic - as reported ................................................. $ 1.34 $ 0.09
Basic - pro forma ................................................... 1.34 0.03
Diluted - as reported ............................................... $ 1.33 $ 0.08
Diluted - pro forma ................................................. 1.33 0.03
3. EARNINGS PER SHARE
SFAS No. 128, Earnings per Share, requires a reconciliation of the
numerator (income) and denominator (shares) of the basic earnings per share
computation to the numerator and denominator of the diluted earnings per share
computation. The reconciliation is as follows:
Quarter Ended March 31,
--------------------------------------
2003 2002
----------------- ------------------
Net Net
Income Shares Income Shares
------- ------ ------- ------
(In thousands)
Earnings - Basic ..................... $25,713 19,199 $ 1,462 17,000
Effect of dilutive securities
Stock options and restricted stock -- 106 -- 122
Shares held by benefit trust ..... -- -- (38) 54
------- ------ ------- ------
Earnings - Diluted ................... $25,713 19,305 $ 1,424 17,176
======= ====== ======= ======
4. DISCONTINUED OPERATIONS
Brea-Olinda. In February 2003, we sold our Brea-Olinda field located in
California for approximately $59.0 million less purchase price adjustments of
$2.4 million. Historical results of operations from this property are classified
as discontinued operations in our statements of income. Revenues associated with
these properties were $3.2 million in the three months ended March 31, 2003 and
$3.4 million in the same period of 2002. Pre-tax income associated with these
properties was $2.6 million in the three months ended March 31, 2003 and $1.1
million in the same period of 2002.
9
Union Island. In March 2003, we sold our Union Island field located in
California for approximately $10.5 million less purchase price adjustments of
$1.7 million and recognized a gain on the sale of $7.7 million. Revenues
associated with these properties were $1.5 million in the three months ended
March 31, 2003 and $0.6 million in the same period of 2002. Pre-tax income
associated with these properties was $1.3 million in the three months ended
March 31, 2003 and $0.4 million in the same period of 2002.
Orcutt Hill. In the first quarter 2003, our Board approved the sale of our
Orcutt Hill field located in California. We transferred the remaining basis in
this field to assets held for sale and recognized a $5.3 million loss in
connection with writing down the basis to the estimated fair value less our
costs to sell. Revenues associated with these properties were $2.7 million in
the three months ended March 31, 2003 and $1.7 million in the same period of
2002. Pre-tax income associated with these properties was $1.3 million in the
three months ended March 31, 2003 and $0.1 million in the same period of 2002.
Eastern Properties. In 2002, we sold a majority of our oil and gas
properties located in Texas, Alabama and Louisiana. Historical results of
operations from these properties are classified as discontinued operations in
our consolidated statements of income. Revenues associated with these properties
were $1.5 million and pre-tax income was $0.3 million in the three months ended
March 31, 2002.
5. PRO FORMA SUMMARY INFORMATION - ACQUISITION OF ATHANOR
On September 18, 2002, we acquired Athanor Resources, Inc. (Athanor) for
$61.3 million in cash, the issuance of approximately $20.1 million of our common
stock (approximately 2.0 million shares) and the assumption of net liabilities
with a fair value of approximately $20.0 million.
The following unaudited pro forma condensed income statement information
has been prepared to give effect to the merger as if the transaction had
occurred at the beginning of the period presented. The historical results of
operations, based on first quarter 2002 realized prices, have been adjusted to
reflect the difference between Athanor's historical depletion, depreciation and
amortization and such expense calculated based on the value allocated to the
assets acquired in the merger. The information presented is not necessarily
indicative of the results of future operations of the merged companies.
Quarter Ended
March 31, 2002
--------------
(In thousands,
except per
share data)
Revenues ......................................................... $ 75,261
Income from continuing operations ................................ 639
Net income ....................................................... 1,728
Earnings per share
Basic
Income from continuing operations ......................... $ 0.03
Net income ................................................ 0.09
Diluted
Income from continuing operations ......................... $ 0.03
Net income ................................................ 0.09
10
6. LONG-TERM DEBT
Our long-term debt consists of the following:
March 31, December 31,
2003 2002
--------- ------------
(In thousands)
9 3/8% Senior Subordinated Notes due 2010 ....... $ 150,000 $ 150,000
9 1/2% Senior Subordinated Notes due 2008 ....... 257,210 257,210
9 1/2% Senior Subordinated Notes due 2006 ....... 2,367 2,367
Bank credit facility (3.81% on December 31, 2002) -- 28,700
--------- ------------
Total debt .................................. 409,577 438,277
Interest rate swaps - fair value adjustment ..... 2,392 2,161
Interest rate swaps - termination gain .......... 11,383 11,673
--------- ------------
Total debt and interest rate swaps .............. 423,352 452,111
Less current portion of long-term debt .......... (2,367) --
--------- ------------
Long-term debt .................................. $ 420,985 $ 452,111
========= ============
We called our 9 1/2% Senior Subordinated Notes due 2006 and completed the
redemption in April 2003.
7. FINANCIAL INSTRUMENTS
We have entered into commodity swaps, collars, put options and interest
rate swaps. The commodity swaps, collars and put options are designated as cash
flow hedges and the interest rate swaps are designated as fair value hedges in
accordance with SFAS No. 133. Quantities covered by the commodity swaps and put
options are based on West Texas Intermediate ("WTI") barrels. Our production is
expected to average 74% of WTI, therefore, each WTI barrel hedges 1.36 barrels
of our production.
Derivative Instruments Designated as Cash Flow Hedges
At March 31, 2003, we had entered into the following cash flow hedges:
Crude Oil Natural Gas
---------------------------------------- -------------------------------------
Bbls / day $ / Bbl Index MMbtu/day $/MMbtu Index
----------- ------------- -------- --------- ----------- ---------
Swaps for Sales
---------------
2003
2nd Qtr. 14,500 $ 23.85 WTI 4,000 $ 4.38 Waha
3rd Qtr. 13,500 23.62 WTI 4,000 4.41 Waha
4th Qtr. 13,000 23.68 WTI 4,000 4.38 Waha
2004
1st Qtr. 13,500 23.56 WTI 8,000 4.34 Waha
2nd Qtr. 11,500 23.82 WTI 3,000 3.91 Waha
3rd Qtr. 9,500 23.50 WTI 3,000 3.91 Waha
4th Qtr. 4,500 22.82 WTI 3,000 3.91 Waha
2005
Full Year 4,500 22.14 WTI
Collars
-------
2003
Full Year 10,000 22.00 - 28.91 WTI
2nd Qtr. - 4th Qtr. 6,000 3.70-4.30 Waha
Swaps for Purchases
-------------------
2004 8,000 3.91 Socal
2005 8,000 3.85 Socal
11
Derivative Instruments Designated as Fair Value Hedges.
In late December 2001 and early 2002, we entered into three interest rate
swap agreements with notional amounts totaling $200.0 million to hedge the fair
value of our 9 -1/2% Notes due 2008 and our 9 3/8% Notes due 2010. These swaps
were designated as fair value hedges and were reflected as an increase or
decrease of long-term debt with a corresponding increase in long-term assets or
liabilities.
In late August and early September 2002, we terminated our swap
transactions relating to these Notes. As a result of these terminations, we
received accrued interest of $2.2 million and the present value of the swap
option of $9.6 million on our 9 3/8% Notes and $0.5 million in accrued interest
and the present value of the swap option of $2.5 million on our 9 -1/2% Notes.
The gain of $9.6 million on our 9 3/8% Notes and $2.5 million on our 9 -1/2%
Notes is reflected as an increase of long-term debt is being amortized as a
periodic reduction in interest expense over the life of the Notes. During the
three months ended March 31, 2003, we amortized $0.3 million as a reduction of
interest expense.
In late August and early November 2002, we entered into two interest rate
swap agreements with notional amounts totaling $100.0 million, to hedge a
portion of the fair value of our 9 3/8% Notes due 2010. These swaps are
designated as fair value hedges and are reflected as an increase of long-term
debt of $2.4 million as of March 31, 2003, with a corresponding increase in
long-term assets. Under the terms of the first agreement, the counterparty pays
us a weighted average fixed annual rate of 9 3/8% on total notional amounts of
$50.0 million, and we pay the counterparty a variable annual rate equal to the
six-month LIBOR rate plus a weighted average rate of 4.71%. Under the terms of
the second agreement, the counterparty pays us a weighted average fixed annual
rate of 9 3/8% on total notional amounts of $50.0 million, and we pay the
counterparty a variable annual rate equal to the six-month LIBOR rate plus a
weighted average rate of 4.95%.
Other - Call Spreads.
We have a call spread that is not designated as a hedging instrument and
is marked-to-market with changes in fair value recognized currently as a
derivative gain/loss. During the three months ended March 31, 2003 we recorded a
$0.9 million derivative loss and recorded the fair value of the remaining
derivative loss at March 31, 2003 totaling $3.7 million in accrued liabilities.
8. SEGMENTS
Our operations consist of the acquisition, exploitation, exploration,
development and production of crude oil and natural gas. Our reportable segments
are domestic, foreign and other. Financial information by reportable segment is
presented below:
For the Quarter Ended March 31, 2003
---------------------------------------------------
Oil and Gas Oil and Gas
Domestic Foreign Other (1) Total
----------- ----------- --------- --------
(In thousands)
Revenues from external customers .. $ 86,631 $ 11,481 $ 138 $ 98,250
Operating income before income tax 35,302 5,650 (19,844) 21,108
For the Quarter Ended March 31, 2002
---------------------------------------------------
Oil and Gas Oil and Gas
Domestic Foreign Other (1) Total
----------- ----------- --------- --------
(In thousands)
Revenues from external customers.. $ 63,537 $ 7,425 $ 6 $ 70,968
Operating income before income tax 16,283 2,371 (18,030) 624
----------
(1) Other includes corporate income and expenses.
12
9. COMMITMENTS AND CONTINGENCIES
We acquired properties from Unocal and are obligated to make a contingent
payment through 2004 if oil prices exceed thresholds set forth in the agreement
with Unocal. Contingent payments are accounted for as a purchase price
adjustment to oil and gas properties. We paid $10.8 million to Unocal in 2002
attributable to calendar year 2001 and recorded the payment in oil and gas
properties. In March 2003, we advised Unocal that we had failed to take
deductions to the purchase price that we believe are permitted by the agreement.
Application of these deductions result in no payment due for either calendar
year 2001 or 2002. Unocal disputes this position for both years and discussions
are ongoing in an effort to resolve this issue. While the outcome of this matter
is not presently determinable, its resolution is not expected to have a
significant impact on our operating results, financial condition or liquidity.
On December 18, 2002, a lawsuit was filed by Hills for Everyone, a
non-profit corporation, against Orange County and us challenging the adequacy of
the Environment Impact Report for the Company's Tonner Hills real estate
project. The suit seeks to compel Orange County to set aside its decision to
adopt the Environment Impact Report and seeks additional environmental analysis
and mitigation measures. We are contesting the litigation and both the county
and we are continuing to take the necessary regulatory steps to move the project
toward development.
On June 15, 2001, we experienced a failure of a carbon dioxide treatment
vessel at the Rincon Onshore Separation Facility ("ROSF") located in Ventura
County, California. There were no injuries associated with this event. Crude oil
and natural gas produced from three fields offshore California are transported
onshore by pipeline to the ROSF plant where crude oil and water are separated
and treated, and carbon dioxide is removed from the natural gas stream. The
daily net production associated with these fields was 3,000 barrels of crude oil
and 2.4 MMcf of natural gas in 2001, representing approximately 6% of our daily
production. In early July 2001, crude oil production resumed and full gas sales
resumed by mid August 2001. The cost of repair and business interruption (less a
30-day waiting period) are expected to be covered by insurance. We expect to
settle the insurance claims within the next three months.
In September 1997, there was a spill of crude oil into the Santa Barbara
Channel from a pipeline that connects our Point Pedernales field with
shore-based processing facilities. The volume of the spill was estimated to be
163 Bbls of oil. Repairs were completed by the end of 1997, and production
recommenced in December 1997. The costs of the clean up and the cost to repair
the pipeline either have been or are expected to be covered by our insurance,
less a deductible of $0.1 million. As of March 31, 2003, we had received
insurance reimbursements of $4.2 million, with a remaining insurance receivable
of $0.5 million. Costs related to the settlement of claims for natural resource
damage asserted by certain federal and state agencies were covered by insurance.
Our international investments involve risks typically associated with
investments in emerging markets such as an uncertain political, economic, legal
and tax environment and expropriation and nationalization of assets. In
addition, if a dispute arises in our foreign operations, we may be subject to
the exclusive jurisdiction of foreign courts or may not be successful in
subjecting foreign persons to the jurisdiction of the United States. We attempt
to conduct our business and financial affairs to protect against political and
economic risks applicable to operations in the various countries where we
operate, but there can be no assurance that we will be successful in so
protecting ourselves. A portion of our investment in the Congo is insured
through political risk insurance provided by Overseas Private Investment
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.
In connection with our February 1995 acquisitions of two subsidiaries
owning interests in the Yombo field offshore Congo, we and a wholly-owned
subsidiary of CMS NOMECO Oil & Gas Co. ("CMS") agreed with the seller of the
subsidiaries not to claim certain tax losses ("dual consolidated losses")
incurred by such subsidiaries prior to the acquisitions. Under the tax law in
the Congo, as it existed when this acquisition took place, if an entity is
acquired in its entirety and that entity has certain tax attributes, for example
tax loss carry forwards from operations in the Republic of Congo, the subsequent
owners of that entity can continue to utilize those losses without restriction.
Pursuant to the agreement, we and CMS may be liable to the seller for the
recapture of dual consolidated losses (net operating losses of any domestic
corporation that are subject to an income tax of a foreign country without
regard to the source of its income or on a residence basis) utilized by the
13
seller in years prior to the acquisitions if certain triggering events occur,
including: (i) a disposition by either us or CMS of its respective Congo
subsidiary, (ii) either Congo subsidiary's sale of its interest in the Yombo
field, (iii) the acquisition of us or CMS by another consolidated group or (iv)
the failure of CMS's Congo subsidiary or us to continue as a member of its
respective consolidated group.
A triggering event will not occur, however, if a subsequent purchaser
enters into certain agreements specified in the consolidated return regulations
intended to ensure that such dual consolidated losses will not be claimed. The
only time limit associated with the occurrence of a triggering event relates to
the utilization of a dual consolidated loss in a foreign jurisdiction. A dual
consolidated loss that is utilized to offset income in a foreign jurisdiction is
only subject to recapture for 15 years following the year in which the dual
consolidated loss was incurred for U.S. income tax purposes. We and CMS have
agreed among ourselves that the party responsible for the triggering event shall
indemnify the other for any liability to the seller as a result of such
triggering event. Our potential direct liability could be as much as $35.4
million if a triggering event with respect to us occurs. Additionally, we
believe that CMS's liability (for which we would be jointly liable with an
indemnification right against CMS) could be as much as $53.1 million. CMS sold
their interest in the Yombo field in 2002 to a U.S. subsidiary of Perenco, S.A.
(Perenco). The sale was not a triggering event as both CMS and Perenco filed a
request for a Closing Agreement with the Internal Revenue Service in accordance
with the U.S. consolidated tax return regulations prior to the sale. Further, we
do not expect a triggering event to occur with respect to Nuevo, CMS or Perenco,
and do not believe the agreement will have a material adverse effect upon us.
14
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
Our results of operations are significantly affected by fluctuations in
oil and gas prices. The following table reflects our production and average
prices for oil and natural gas:
Quarter Ended March 31,
------------------------
2003 2002
-------- ----------
Crude Oil and Liquids
Sales Volumes (MBbls/day)
Domestic ................................... 37.2 37.7
Foreign ....................................
4.9 5.0
-------- ----------
Total ................................... 42.1 42.7
======== ==========
Sales Prices ($/Bbl)
Unhedged ................................... $ 25.51 $ 15.77
Hedged ..................................... 21.83 16.99
Revenues ($/thousands)
Domestic ................................... $ 85,271 $ 53,337
Foreign .................................... 11,481 7,425
Marketing Fees ............................. (4) (194)
Hedging .................................... (13,946) 4,683
-------- ----------
Total ................................. $ 82,802 $ 65,251
======== ==========
Natural Gas
Sales Volumes (MMcf/day)
Domestic ................................... 39.4 28.4
======== ==========
Sales Prices ($/Mcf)
Unhedged ................................... $ 4.80 $ 2.23
Hedged ..................................... 4.32 2.23
Revenues ($/thousands)
Domestic ................................... $ 17,106 $ 5,799
Marketing Fees ............................. (93) (88)
Hedging .................................... (1,703) --
-------- ----------
Total ................................. $ 15,310 $ 5,711
======== ==========
----------
Below is a list of terms commonly used in the oil and gas industry.
/d = per day
Bbl = barrel of crude oil or other liquid hydrocarbons
Bcf = billion cubic feet of natural gas
Bcfe = billion cubic feet of natural gas equivalent
BOE = barrel of oil equivalent, converting gas to oil at the ratio of
6 Mcf of gas to 1 Bbl of oil
BOPD = barrel of oil per day
MBbl = thousand barrels
Mcf = thousand cubic feet of natural gas
MMBbl = million barrels of oil or other liquid hydrocarbons
MMcf = million cubic feet of natural gas
MBOE = thousand barrels of oil equivalent
MMBOE = million barrels of oil equivalent
15
QUARTER ENDED MARCH 31, 2003 COMPARED TO QUARTER ENDED MARCH 31, 2002
We had net income of $25.7 million, or $1.33 per diluted share for the
quarter ended March 31, 2003 as compared to net income of $1.5 million, or $0.08
per diluted share in the same period of 2002.
Revenues
Oil and Gas Revenues. Oil and gas revenues increased 38% to $98.1 million
for the three months ended March 31, 2003 from $71.0 million in the same period
of 2002 due to higher realized crude oil and natural gas prices and higher
natural gas production which was partially offset by higher hedging losses in
2003. Crude oil production averaged 42.1 MBbls/day for the three months ended
March 31, 2003 compared to 42.7 MBbls/day in the same period of 2002 primarily
due to lower production offshore California due to mechanical downtime. The
realized oil price for the three months ended March 31, 2003 was $21.83 per Bbl,
an increase of $4.84 per Bbl from the same period in 2002. We had hedging losses
of $13.9 million in the three months ended March 31, 2003 compared to hedging
gain of $4.7 million in same period of 2002. Natural gas production averaged
39.4 MMcf per day for the three months ended March 31, 2003 compared to 28.4
MMcf per day for the same period of 2002. The increase was primarily due to
production from the Pakenham field which was acquired in September 2002. The
realized natural gas price for the three months ended March 31, 2003 was $4.32
per Mcf, an increase of $2.09 per Mcf from the comparable period in 2002. In the
three months ended March 31, 2003, we had gas hedging losses of $0.48 per Mcf.
We had no gas hedged in the 2002 period.
Costs and Expenses
Costs and Expenses. Lease operating expenses ("LOE") for the three months
ended March 31, 2003 totaled $39.3 million, as compared to $34.6 million for the
2002 period. The increased LOE was due to higher steam costs in our onshore
California operations and costs from our Pakenham field which was purchased in
2002. Exploration costs were $1.1 million in both the three months ended March
31, 2003 and 2002. Exploration costs in 2003 included dry hole cost of the Chott
Fejaj well in Tunisia while the 2002 costs were primarily seismic costs.
Depletion, depreciation, amortization and accretion ("DD&A") of $17.4 million
for the three months ended March 31, 2003, increased $0.2 million from the same
period of 2002 primarily due to higher natural gas production and accretion
expense related to the January 2003 adoption of SFAS 143. The DD&A rate was
$3.97 per BOE in the 2003 period compared to $4.04 per BOE in 2002. General and
administrative expense of $6.7 million in 2003 was $0.6 million higher than the
comparable period in 2002 due to higher employee costs, severance and insurance
in 2003.
Derivative Gain (Loss). Our derivative loss for the quarter ended March
31, 2003 was $0.9 million compared to a loss of $0.8 million in the same period
of 2002. The derivative loss is comprised of a loss on our mark-to-market
derivatives and the ineffective portion of certain of our hedges.
Interest Expense. Interest expense was $9.3 million for the three months
ended March 31, 2003 compared to interest expense of $9.0 million in the same
period of 2002. Lower interest expense on the line of credit of $0.3 million and
lower facility fees of $0.2 million were more than offset by a lower benefit on
the interest rate swaps of $0.9 million which was due to lower debt swapped in
2003.
Dividends. Dividends on the TECONS were $1.7 million in both the three
months ended March 31, 2003 and 2002. The TECONS pay dividends at a rate of
5.75% and were issued in December 1996.
Income Tax. We had income tax expense of $8.4 million including current
tax of $1.5 million for the three months ended March 31, 2003 compared to an
expense of $0.3 million in the prior year period which had no current tax. The
current tax relates to income tax in California, which deferred the use of net
operating losses in 2002 and 2003, and Federal income tax. Our effective income
tax rate was 40.0% in 2003 and 40.1% in 2002.
Discontinued Operations. We had income from discontinued operations of
$4.6 million for the three months ended March 31, 2003 compared to income of
$1.1 million in same period of 2002. In 2003, we sold our Brea-Olinda and Union
Island properties located onshore California and made the decision to sell our
Orcutt Hill property located onshore California. We recognized a $7.7 million
gain on the sale of the Union Island property
16
and a $5.4 million loss in connection with writing down the Orcutt Hill property
to its estimated fair value less its costs to sell. In 2002 the income from
discontinued operations consists of after-tax operating income from our Eastern
fields which were sold in 2001 and operating income from our Brea-Olinda, Union
Island and Orcutt Hill properties.
Cumulative Effect of Change in Accounting Principle. In January 2003, we
adopted Statement of Financial Accounting Standards ("SFAS") No. 143. In
connection with the initial application, we recorded a cumulative effect of
change in accounting principle, net of taxes, of $8.5 million as an increase to
income. (See Note 1 to the Condensed Consolidated Financial Statements).
CAPITAL RESOURCES AND LIQUIDITY
We have grown and diversified our operations through acquisitions of oil
and gas properties and the subsequent exploitation and development of these
properties. We have historically funded our operations and acquisitions with
operating cash flows, bank financing, private and public placements of debt and
equity securities, property divestitures and joint ventures with industry
participants.
Net cash provided by operating activities was $47.1 million for the
quarter ended March 31, 2003. In 2003, we invested $16.2 million in oil and gas
properties and $0.7 million on other properties. We also received $65.4 million
in proceeds from the sale of properties during the quarter ended March 31, 2003.
We believe our working capital, cash flow from operations and available
financing sources are sufficient to meet our obligations as they become due and
to finance our capital budget through 2003. We have a $150 million borrowing
base under our Credit Agreement. Under the most restrictive covenant, the entire
$150 million was available at March 31, 2003 and we had no borrowings
outstanding. We have one letter of credit of $0.8 million under our Credit
Agreement. We have interest rate swaps totaling $100 million on our 9 3/8 %
Notes due 2010.
CONTINGENCIES AND OTHER MATTERS
We acquired properties from Unocal and are obligated to make a contingent
payment through 2004 if oil prices exceed thresholds set forth in the agreement
with Unocal. Contingent payments are accounted for as a purchase price
adjustment to oil and gas properties. We paid $10.8 million to Unocal in 2002
attributable to calendar year 2001 and recorded the payment in oil and gas
properties. In March 2003, we advised Unocal that we had failed to take
deductions to the purchase price that we believe are permitted by the agreement.
Application of these deductions result in no payment due for either calendar
year 2001 or 2002. Unocal disputes this position for both years and discussions
are ongoing in an effort to resolve this issue. While the outcome of this matter
is not presently determinable, its resolution is not expected to have a
significant impact on our operating results, financial condition or liquidity.
On December 18, 2002, a lawsuit was filed by Hills for Everyone, a
non-profit corporation, against Orange County and us challenging the adequacy of
the Environment Impact Report for the Company's Tonner Hills real estate
project. The suit seeks to compel Orange County to set aside its decision to
adopt the Environment Impact Report and seeks additional environmental analysis
and mitigation measures. We are contesting the litigation and both the county
and we are continuing to take the necessary regulatory steps to move the project
toward development.
On June 15, 2001, we experienced a failure of a carbon dioxide treatment
vessel at the Rincon Onshore Separation Facility ("ROSF") located in Ventura
County, California. There were no injuries associated with this event. Crude oil
and natural gas produced from three fields offshore California are transported
onshore by pipeline to the ROSF plant where crude oil and water are separated
and treated, and carbon dioxide is removed from the natural gas stream. The
daily net production associated with these fields was 3,000 barrels of crude oil
and 2.4 MMcf of natural gas in 2001, representing approximately 6% of our daily
production. In early July 2001, crude oil production resumed and full gas sales
resumed by mid August 2001. The cost of repair and business interruption (less a
30-day waiting period) are expected to be covered by insurance. We expect to
settle the insurance claims within the next three months.
In September 1997, there was a spill of crude oil into the Santa Barbara
Channel from a pipeline that connects our Point Pedernales field with
shore-based processing facilities. The volume of the spill was estimated
17
to be 163 Bbls of oil. Repairs were completed by the end of 1997, and production
recommenced in December 1997. The costs of the clean up and the cost to repair
the pipeline either have been or are expected to be covered by our insurance,
less a deductible of $0.1 million. As of March 31, 2003, we had received
insurance reimbursements of $4.2 million, with a remaining insurance receivable
of $0.5 million. Costs related to the settlement of claims for natural resource
damage asserted by certain federal and state agencies were covered by insurance.
Our international investments involve risks typically associated with
investments in emerging markets such as an uncertain political, economic, legal
and tax environment and expropriation and nationalization of assets. In
addition, if a dispute arises in our foreign operations, we may be subject to
the exclusive jurisdiction of foreign courts or may not be successful in
subjecting foreign persons to the jurisdiction of the United States. We attempt
to conduct our business and financial affairs to protect against political and
economic risks applicable to operations in the various countries where we
operate, but there can be no assurance that we will be successful in so
protecting ourselves. A portion of our investment in the Congo is insured
through political risk insurance provided by Overseas Private Investment
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.
In connection with our February 1995 acquisitions of two subsidiaries
owning interests in the Yombo field offshore Congo, we and a wholly-owned
subsidiary of CMS NOMECO Oil & Gas Co. ("CMS") agreed with the seller of the
subsidiaries not to claim certain tax losses ("dual consolidated losses")
incurred by such subsidiaries prior to the acquisitions. Under the tax law in
the Congo, as it existed when this acquisition took place, if an entity is
acquired in its entirety and that entity has certain tax attributes, for example
tax loss carry forwards from operations in the Republic of Congo, the subsequent
owners of that entity can continue to utilize those losses without restriction.
Pursuant to the agreement, we and CMS may be liable to the seller for the
recapture of dual consolidated losses (net operating losses of any domestic
corporation that are subject to an income tax of a foreign country without
regard to the source of its income or on a residence basis) utilized by the
seller in years prior to the acquisitions if certain triggering events occur,
including: (i) a disposition by either us or CMS of its respective Congo
subsidiary, (ii) either Congo subsidiary's sale of its interest in the Yombo
field, (iii) the acquisition of us or CMS by another consolidated group or (iv)
the failure of CMS's Congo subsidiary or us to continue as a member of its
respective consolidated group.
A triggering event will not occur, however, if a subsequent purchaser
enters into certain agreements specified in the consolidated return regulations
intended to ensure that such dual consolidated losses will not be claimed. The
only time limit associated with the occurrence of a triggering event relates to
the utilization of a dual consolidated loss in a foreign jurisdiction. A dual
consolidated loss that is utilized to offset income in a foreign jurisdiction is
only subject to recapture for 15 years following the year in which the dual
consolidated loss was incurred for U.S. income tax purposes. We and CMS have
agreed among ourselves that the party responsible for the triggering event shall
indemnify the other for any liability to the seller as a result of such
triggering event. Our potential direct liability could be as much as $35.4
million if a triggering event with respect to us occurs. Additionally, we
believe that CMS's liability (for which we would be jointly liable with an
indemnification right against CMS) could be as much as $53.1 million. CMS sold
their interest in the Yombo field in 2002 to a U.S. subsidiary of Perenco, S.A.
(Perenco). The sale was not a triggering event as both CMS and Perenco filed a
request for a Closing Agreement with the Internal Revenue Service in accordance
with the U.S. consolidated tax return regulations prior to the sale. Further, we
do not expect a triggering event to occur with respect to Nuevo, CMS or Perenco,
and do not believe the agreement will have a material adverse effect upon us.
NEW ACCOUNTING PRONOUNCEMENTS
Amendment of Statement 133 on Derivative Instruments and Hedging Activities.
In April 2003, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 149, Amendment of
Statement 133 on Derivative Instruments and Hedging Activities. The statement
amends and clarifies accounting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities
under SFAS No. 133. Except for implementation issues that have been effective
for fiscal quarters that began prior to June 15, 2003 and should continue to be
applied in accordance with their effective dates, this statement is effective
for contracts entered into or modified after June 30, 2003 and for hedging
relationships designated after June 30, 2003. The financial statement provisions
are effective prospectively, except for forward purchases or sales of
when-issued securities or
18
other securities that do not yet exist and in which case SFAS No. 149 should be
applied to both existing contracts and new contracts entered into after June 30,
2003. We are currently evaluating the effects of this pronouncement.
Accounting for Asset Retirement Obligations.
In August 2001, the FASB issued SFAS No. 143, Accounting for Asset
Retirement Obligations. This Statement requires a liability to be recorded
relating to the eventual retirement and removal of assets used in our business.
The liability is discounted to its present value, with a corresponding increase
to the related asset value. Over the life of the asset, the liability will be
accreted to its future value and eventually extinguished when the asset is taken
out of service. The provisions of this Statement are effective for fiscal years
beginning after June 15, 2002. We adopted the provisions of SFAS No. 143 on
January 1, 2003 to record our asset retirement obligation to plug and abandon
oil and gas wells. In connection with the initial application of SFAS No. 143,
we recorded a cumulative effect of change in accounting principle, net of taxes,
of $8.5 million as an increase to net income. In addition, we recorded an asset
retirement obligation for oil and gas properties and equipment of $87.8 million.
The following table summarizes asset retirement obligation transactions recorded
in accordance with the provisions of SFAS No. 143:
Quarter Ended
March 31, 2003
------------------
(In thousands)
Beginning asset retirement obligation............ $ 87,828
Liabilities incurred during period............... 2,304
Liabilities settled during period................ (481)
Accretion expense................................ 2,123
------------------
Ending asset retirement obligation............... $ 91,774
==================
The following table summarizes the pro forma basis as required by SFAS No.
143, had we adopted the provisions of SFAS No. 143 prior to January 1, 2003, the
amount of the asset retirement obligations would have been as follows:
Pro Forma
Asset Retirement
Adoption Date Obligation
------------- ----------------
(In thousands)
January 1, 2000................. $ 65,621
December 31, 2000............... 72,706
December 31, 2001............... 80,062
March 31, 2002.................. 81,687
December 31, 2002............... 87,828
In addition, pro forma net income and earnings per share for the three
months ended March 31, 2002 and for the years ended December 31, 2002, 2001 and
2000 for the change in accounting had it been implemented during the periods:
1st Qtr
2002 2002 2001 2000
---------- ---------- ---------- ----------
(In thousands, except per share data)
Net income
As Reported $ 1,462 $ 12,275 $ (79,171) $ 11,635
Pro Forma 2,750 14,897 (75,479) 11,624
Net income per share - Reported
Basic 0.09 0.70 (4.73) 0.67
Diluted 0.08 0.69 (4.73) 0.64
Net income per share - Pro Forma
Basic 0.16 0.84 (4.51) 0.67
Diluted 0.16 0.84 (4.51) 0.65
19
Guarantor's Accounting and Disclosure Requirements.
In November 2002, the FASB issued Interpretation No. 45 ("FIN 45"),
Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of the Indebtedness of Others, which clarifies the
requirements of SFAS No. 5, Accounting for Contingencies, relating to a
guarantor's accounting for and disclosures of certain guarantees issued. FIN 45
requires enhanced disclosures for certain guarantees. It also will require
certain guarantees that are issued or modified after December 31, 2002,
including certain third-party guarantees, to be initially recorded on the
balance sheet at fair value. For guarantees issued on or before December 3,
2002, liabilities are recorded when and if payments become probable and
estimable. The financial statement recognition provisions are effective
prospectively, and we cannot reasonably estimate the impact of FIN 45 until
guarantees are issued or modified in future periods, at which time their results
will be initially reported in the financial statements.
Consolidation of Variable Interest Entities.
In January 2003, the FASB issued Interpretation No. 46 ("FIN 46"),
Consolidation of Variable Interest Entities, an interpretation of Accounting
Research Bulletin No. 51. FIN 46 requires certain variable interest entities, or
VIEs, to be consolidated by the primary beneficiary of the entity if the equity
investors in the entity do not have the characteristics of a controlling
financial interest or do not have sufficient equity at risk for the entity to
finance its activities without additional subordinated financial support from
other parties. FIN 46 is effective for all VIEs created or acquired after
January 31, 2003. For VIEs created or acquired prior to February 1, 2003, the
provisions of FIN 46 must be applied for the first interim or annual period
beginning after June 15, 2003. We currently have no contractual relationship or
other business relationship with a variable interest entity and therefore the
adoption of FIN 46 will have no effect on our consolidated financial position,
results of operations or cash flows.
20
CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995
This report contains or incorporates by reference forward looking
statements within the meaning of Section 27A of the Securities Act of 1933, as
amended, Section 21E of the Securities Exchange Act of 1934 and the Private
Securities Litigation Reform Act of 1995. All statements other than statements
of historical facts included in this document, including without limitation,
statements in Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operations regarding our financial position, estimated
quantities and net present values of reserves, business strategy, plans and
objectives of our management for future operations and covenant compliance, are
forward looking statements. We can give no assurances that the assumptions upon
which such forward-looking statements are based will prove to be correct.
Important factors that could cause actual results to differ materially from our
expectations are included throughout this document. The cautionary statements
expressly qualify all subsequent written and oral forward-looking statements
attributable to us or persons acting on our behalf.
21
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information contained in this item updates, and should be read in
conjunction with Part II, Item 7A of our Annual Report on Form 10-K for the year
ended December 31, 2002.
At March 31, 2003, we had entered into the following cash flow hedges:
Crude Oil Natural Gas
---------------------------------------- ------------------------------------
Bbls / day $ / Bbl Index MMbtu/day $/MMbtu Index
----------- -------------- ------- --------- ---------- ---------
Swaps for Sales
---------------
2003
2nd Qtr. 14,500 $ 23.85 WTI 4,000 $ 4.38 Waha
3rd Qtr. 13,500 23.62 WTI 4,000 4.41 Waha
4th Qtr. 13,000 23.68 WTI 4,000 4.38 Waha
2004
1st Qtr. 13,500 23.56 WTI 8,000 4.34 Waha
2nd Qtr. 11,500 23.82 WTI 3,000 3.91 Waha
3rd Qtr. 9,500 23.50 WTI 3,000 3.91 Waha
4th Qtr. 4,500 22.82 WTI 3,000 3.91 Waha
2005
Full Year 4,500 22.14 WTI
Collars
-------
2003
Full Year 10,000 22.00 - 28.91 WTI
2nd Qtr. - 4th Qtr. 6,000 3.70-4.30 Waha
Swaps for Purchases
-------------------
2004 8,000 3.91 Socal
2005 8,000 3.85 Socal
Subsequent to March 31, 2003, we entered into the following cash flow
hedges:
Crude Oil Natural Gas
---------------------------------------- ------------------------------------
Bbls / day $ / Bbl Index MMbtu/day $/MMbtu Index
----------- -------------- ------- --------- ---------- ---------
Swaps for Sales
---------------
2003
3rd Qtr. 3,500 $ 5.45 Waha
4th Qtr. 4,000 5.50 Waha
2004
1st Qtr 8,500 5.48 Waha&
Socal
2nd Qtr. 4,000 4.50 Waha
3rd Qtr. 1,500 $ 24.50 WTI 4,000 4.51 Waha
4th Qtr. 2,000 24.14 WTI 4,000 4.50 Waha
22
ITEM 4. CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
The term "disclosure controls and procedures" is defined in Rule 13a-14(c)
of the Securities Exchange Act of 1934, or the Exchange Act. This term refers to
the controls and procedures of a company that are designed to ensure that
information required to be disclosed by a company in the reports that it files
under the Exchange Act is recorded, processed, summarized and reported within
required time periods. Our Chief Executive Officer and our Chief Financial
Officer have evaluated the effectiveness of our disclosure controls and
procedures as of a date within 90 days before the filing of the quarterly
report, and they have concluded that as of that date, our disclosure controls
and procedures were effective at ensuring that required information will be
disclosed on a timely basis in our reports filed under the Exchange Act.
CHANGE IN INTERNAL CONTROLS
We maintain a system of internal controls that are designed to provide
reasonable assurance that our books and records accurately reflect our
transactions and that our established policies and procedures are followed.
There were no significant changes to our internal controls or in other factors
that could significantly affect our internal controls subsequent to the date of
their evaluation by our Chief Executive Officer and our Chief Financial Officer,
including any corrective actions with regard to significant deficiencies and
material weaknesses.
23
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Part I, Item 1, Financial Statements, Note 9, which is incorporated
herein by reference.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS
None.
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(A) EXHIBITS
- 99.1 Certification of Chief Executive Officer of Nuevo Energy
Company
- 99.2 Certification of Chief Financial Officer of Nuevo Energy
Company
(B) REPORTS ON FORM 8-K:
None.
24
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) the Securities Exchange Act
of 1934, the Registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
NUEVO ENERGY COMPANY
(Registrant)
Date: May 13, 2003 By: /s/ James L. Payne
-------------------- ----------------------------------
James L. Payne
Chairman, President and
Chief Executive Officer
Date: May 13, 2003 By: /s/ Janet F. Clark
-------------------- ----------------------------------
Janet F. Clark
Senior Vice President and
Chief Financial Officer
25
EXHIBIT INDEX
Exhibit
Number Description
------ -----------
99.1 Certification of Chief Executive Officer of Nuevo Energy Company
99.2 Certification of Chief Financial Officer of Nuevo Energy Company