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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 JUNE 30, 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 July 31,
2003: 19,348,430
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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................................................... 16
Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation Reform Act of 1995.......... 22
Item 3. Quantitative and Qualitative Disclosures About Market Risk......................... 23
Item 4 Disclosure Controls and Procedures................................................. 24
PART II
Item 1. Legal Proceedings.................................................................. 25
Item 2. Changes in Securities and Use of Proceeds.......................................... 25
Item 3. Defaults Upon Senior Securities.................................................... 25
Item 4. Submission of Matters to a Vote of Security-Holders................................ 25
Item 5. Other Information.................................................................. 26
Item 6. Exhibits and Reports on Form 8-K................................................... 26
Signatures ........................................................................ 27
Certifications.....................................................................
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
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 Six Months Ended
June 30, June 30,
---------------------------- --------------------------
2003 2002 2003 2002
------------ ------------ ----------- -----------
Revenues
Crude oil and liquids.......................................... $ 80,818 $ 69,506 $ 163,620 $ 134,757
Natural gas.................................................... 13,428 7,943 28,738 13,654
Other.......................................................... 275 42 413 48
------------ ------------ ----------- -----------
94,521 77,491 192,771 148,459
------------ ------------ ----------- -----------
Costs and Expenses
Lease operating expenses....................................... 42,106 32,414 81,436 67,040
Exploration costs.............................................. 317 424 1,389 1,482
Depletion, depreciation, amortization and accretion............ 17,709 17,458 35,098 34,706
General and administrative expenses............................ 6,346 7,232 13,063 13,315
Loss (gain) on disposition of properties....................... (4,457) (15,326) (4,457) (15,326)
Other.......................................................... (466) (222) 329 (198)
------------ ------------ ----------- -----------
61,555 41,980 126,858 101,019
------------ ------------ ----------- -----------
Operating Income................................................... 32,966 35,511 65,913 47,440
Derivative gain (loss)......................................... (784) (177) (1,727) (933)
Interest income................................................ 224 66 303 174
Interest expense............................................... (9,034) (9,212) (18,356) (18,216)
Loss on early extinguishment of debt........................... (10,892) -- (10,892) --
Dividends on TECONS............................................ (1,653) (1,653) (3,306) (3,306)
------------ ------------ ----------- -----------
Income From Continuing Operations Before Income Tax................ 10,827 24,535 31,935 25,159
Income Tax Expense
Current........................................................ 576 -- 2,080 --
Deferred....................................................... 3,639 9,948 10,580 10,199
------------ ------------ ----------- -----------
4,215 9,948 12,660 10,199
------------ ------------ ----------- -----------
Income From Continuing Operations.................................. 6,612 14,587 19,275 14,960
Income from discontinued operations, including gain/loss on
disposal, net of income tax.................................. 770 1,979 5,324 3,068
Cumulative effect of a change in accounting principle, net of
income tax................................................... -- -- 8,496 --
------------ ------------ ----------- -----------
Net Income......................................................... $ 7,382 $ 16,566 $ 33,095 $ 18,028
============ ============ =========== ===========
Earnings Per Share:
Basic
Income from continuing operations ........................... $ 0.34 $ 0.85 $ 1.00 $ 0.88
Income from discontinued operations, net of income tax....... 0.04 0.12 0.28 0.18
Cumulative effect of a change in accounting principle, net
of income tax............................................ -- -- 0.44 --
------------ ------------ ----------- -----------
Net income................................................... $ 0.38 $ 0.97 $ 1.72 $ 1.06
============ ============ =========== ===========
Diluted
Income from continuing operations............................ $ 0.34 $ 0.84 $ 0.99 $ 0.87
Income from discontinued operations, net of income tax....... 0.04 0.12 0.27 0.18
Cumulative effect of a change in accounting principle, net
of income tax............................................ -- -- 0.44 --
------------ ------------ ----------- -----------
Net income................................................... $ 0.38 $ 0.96 $ 1.70 $ 1.05
============ ============ =========== ===========
Weighted Average Shares Outstanding:
Basic.......................................................... 19,260 17,079 19,230 17,040
============ ============ =========== ===========
Diluted........................................................ 19,507 17,291 19,446 17,237
============ ============ =========== ===========
See accompanying notes.
3
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)
June 30, December 31,
2003 2002
------------ ------------
(UNAUDITED)
ASSETS
Current assets
Cash and cash equivalents................................................................. $ 375 $ 5,047
Accounts receivable, net.................................................................. 48,610 40,945
Inventory ............................................................................... 4,798 7,326
Assets held for sale ..................................................................... 48,154 92,738
Deferred income taxes..................................................................... 10,095 7,683
Prepaid expenses and other................................................................ 6,759 3,862
------------ ------------
Total current assets.................................................................. 118,791 157,601
------------ ------------
Property and equipment, at cost
Land...................................................................................... 5,224 5,224
Oil and gas properties (successful efforts method)........................................ 1,004,371 951,258
Other property............................................................................ 14,626 14,303
------------ ------------
1,024,221 970,785
Accumulated depreciation, depletion and amortization...................................... (324,314) (357,072)
------------ ------------
Total property and equipment, net..................................................... 699,907 613,713
------------ ------------
Deferred income taxes ........................................................................ 25,681 43,258
Goodwill...................................................................................... 17,121 19,664
Other assets.................................................................................. 14,285 20,935
------------ ------------
Total assets....................................................................... $ 875,785 $ 855,171
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable.......................................................................... $ 28,857 $ 34,323
Accrued interest.......................................................................... 4,660 5,169
Accrued drilling costs.................................................................... 6,743 8,035
Accrued lease operating costs............................................................. 16,557 15,598
Price risk management activities.......................................................... 30,321 20,884
Other accrued liabilities................................................................. 28,593 16,735
------------ ------------
Total current liabilities............................................................. 115,731 100,744
------------ ------------
Long-term debt
Senior subordinated notes................................................................. 250,000 409,577
Bank credit facility...................................................................... 66,150 28,700
------------ ------------
Total debt............................................................................ 316,150 438,277
Interest rate swaps - fair value adjustment............................................... -- 2,161
Interest rate swaps - termination gain.................................................... 15,180 11,673
------------ ------------
Long-term debt........................................................................ 331,330 452,111
------------ ------------
Asset retirement obligation................................................................... 99,229 --
Other long-term liabilities................................................................... 9,913 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, 23,082,067 and
23,048,388 shares issued and 19,303,020 and 19,110,102 shares outstanding,
respectively............................................................................ 231 230
Additional paid-in capital................................................................ 390,791 388,479
Treasury stock, at cost, 3,779,047 and 3,867,691 shares, respectively..................... (74,095) (75,683)
Deferred stock compensation and other..................................................... (1,746) (605)
Accumulated other comprehensive income (loss)............................................. (16,530) (11,468)
Accumulated deficit....................................................................... (94,069) (126,677)
------------ ------------
Total stockholders' equity............................................................ 204,582 174,276
------------ ------------
Total liabilities and stockholders' equity......................................... $ 875,785 $ 855,171
============ ============
See accompanying notes.
4
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
Quarter Ended Six Months Ended
June 30, June 30,
--------------------------- --------------------------
2003 2002 2003 2002
----------- ----------- ----------- -----------
Cash flows from operating activities
Net income ................................................ $ 7,382 $ 16,566 $ 33,095 $ 18,028
Adjustments to reconcile net income to net cash provided by
operating activities
Depletion, depreciation, amortization and accretion...... 17,709 17,458 35,098 34,706
Amortization of debt financing costs..................... 548 664 1,181 1,266
Loss on early extinguishment of debt..................... 10,892 -- 10,892 --
Net gain on sales of assets.............................. (4,457) (15,326) (4,457) (15,326)
Deferred income taxes.................................... 3,639 9,948 10,580 10,199
Non-cash effect of discontinued operations............... 461 3,515 494 6,152
Cumulative effect of a change in accounting principle.... -- -- (8,496) --
Other.................................................... 988 407 3,119 1,295
Working capital changes, net of non-cash transactions
Accounts receivable...................................... 11,467 40 (7,429) 3,806
Accounts payable......................................... 23 (4,751) (2,048) (12,564)
Accrued liabilities...................................... (17,835) (9,099) (10,888) (15,487)
Other.................................................... 7,122 (2,737) 23,932 (3,068)
----------- ----------- ----------- -----------
Net cash provided by operating activities............. 37,939 16,685 85,073 29,007
----------- ----------- ----------- -----------
Cash flows from investing activities
Additions to oil and gas properties......................... (14,641) (12,991) (30,854) (28,345)
Additions to other properties............................... (1,072) (1,193) (1,744) (2,206)
Proceeds from sale of properties............................ 4,457 24,856 69,863 24,856
Other investing activities.................................. -- -- 1,841 --
----------- ----------- ----------- -----------
Net cash provided by (used in) investing activities... (11,256) 10,672 39,106 (5,695)
----------- ----------- ----------- -----------
Cash flows from financing activities
Payments of long-term debt.................................. (159,577) -- (159,577) --
Premium paid for redemption of notes........................ (7,505) -- (7,505) --
Net borrowings/repayments of credit facility................ 66,150 (31,175) 37,450 (32,700)
Proceeds from exercise of stock options..................... 781 470 781 1,229
Other proceeds.............................................. -- 1,294 -- 1,294
----------- ----------- ----------- -----------
Net cash used in financing activities................. (100,151) (29,411) (128,851) (30,177)
----------- ----------- ----------- -----------
Increase (decrease) in cash and cash equivalents.............. (73,468) (2,054) (4,672) (6,865)
Cash and cash equivalents
Beginning of period...................................... 73,843 2,299 5,047 7,110
----------- ----------- ----------- -----------
End of period............................................ $ 375 $ 245 $ 375 $ 245
=========== =========== =========== ===========
See accompanying notes.
5
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(IN THOUSANDS)
(UNAUDITED)
Quarter Ended Six Months Ended
June 30, June 30,
-------------------------- ---------------------------
2003 2002 2003 2002
----------- ----------- ----------- -----------
Net income ....................................................... $ 7,382 $ 16,566 $ 33,095 $ 18,028
Unrealized gains (losses) from cash flow hedging activity:
Reclassification adjustment for settled contracts........... 4,013 1,195 1,824 (1,601)
Changes in fair value of derivative instruments during the
period................................................... (5,419) (2,829) (18,354) (14,539)
----------- ----------- ----------- -----------
Other comprehensive income (loss)...................... (1,406) (1,634) (16,530) (16,140)
----------- ----------- ----------- -----------
Comprehensive income (loss)....................................... $ 5,976 $ 14,932 $ 16,565 $ 1,888
=========== =========== =========== ===========
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 June 30,
2003, and for the three and six months ended June 30, 2003 and 2002, are
unaudited. The balance sheet as of December 31, 2002, is derived from the
audited balance sheet included in our Form 10-K. These financial statements have
been prepared pursuant to the rules and regulations of the U.S. Securities and
Exchange Commission ("SEC") 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.
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.
Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity.
In May 2003, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 150, Accounting for
Certain Financial Instruments with Characteristics of both Liabilities and
Equity. SFAS No. 150 establishes standards for how an issuer classifies and
measures three classes of freestanding financial instruments (mandatorily
redeemable instruments, instruments with repurchase obligations, instruments
with obligations to issue a variable number of shares) with characteristics of
both liabilities and equity. Instruments within the scope of the statement must
be classified as liabilities on the balance sheet. SFAS No. 150 is effective for
all freestanding financial instruments entered into or modified after May 31,
2003, and otherwise is effective at the beginning of the first interim period
beginning after June 15, 2003. We have not entered into any financial
instruments within the scope of SFAS No. 150 since May 31, 2003, nor do we
currently hold any significant financial instruments within the scope. SFAS No.
150 does not apply to convertible bonds, consequently our TECONS are not within
the scope of SFAS No. 150.
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 $92.7 million.
The following table summarizes asset retirement obligation transactions recorded
in accordance with the provisions of SFAS No. 143:
Quarter Ended Six Months Ended
June 30, 2003 June 30, 2003
---------------------- ----------------------
(In thousands)
Beginning asset retirement obligation........... $ 96,902 $ 92,680
Liabilities incurred during period.............. 101 2,564
Liabilities settled during period............... (70) (551)
Accretion expense............................... 2,296 4,536
---------------------- ----------------------
Ending asset retirement obligation.............. $ 99,229 $ 99,229
====================== ======================
7
In addition, pro forma net income and earnings per share for the quarter
ended June 30, 2002 and for the six months ended June 30, 2002 for the change in
accounting had SFAS No. 143 been implemented during these periods would have
been as follows:
Quarter Ended Six Months Ended
June 30, 2002 June 30, 2002
---------------------- ----------------------
(In thousands, except per share data)
Net income
As Reported................................ $ 16,566 $ 18,028
Pro Forma.................................. 17,646 20,359
Net income per share - Reported
Basic...................................... 0.97 1.06
Diluted.................................... 0.96 1.05
Net income per share - Pro Forma
Basic...................................... 1.03 1.19
Diluted.................................... 1.02 1.18
Guarantor's Accounting and Disclosure Requirements.
The FASB issued Interpretation No. 45 ("FIN 45"), Guarantor's Accounting
and Disclosure Requirements for Guarantees, Including Indirect Guarantees of the
Indebtedness of Others, in November 2002, 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 requires that certain guarantees
issued or modified after December 31, 2002, including certain third-party
guarantees, be recorded initially on the balance sheet at fair value. For
guarantees issued on or before December 31, 2002, liabilities are recorded when
and if payments become probable and estimable. We adopted FIN 45 effective
January 1, 2003, and have included the disclosure requirements of FIN 45 in Note
9 to the condensed consolidated financial statements. The adoption of FIN 45 did
not have a material effect on our consolidated financial position, results of
operations or cash flows.
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 had no effect on our consolidated financial position, results
of operations or cash flows.
8
Accounting for Costs Associated with Mineral Rights.
The FASB and representatives of the accounting staff of the SEC are
currently engaged in discussions regarding the application of certain provisions
of SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other
Intangible Assets, with companies in the extractive industries, including oil
and gas companies. The FASB and the SEC staff are considering whether the
provisions of SFAS No. 141 and SFAS No. 142 require registrants to classify
costs associated with mineral rights, including both proved and unproved lease
acquisition costs, as intangible assets on the balance sheet, apart from other
capitalized oil and gas property costs, and provide specific footnote
disclosures.
Consistent with industry practice, we historically have included oil and
gas lease acquisition costs as a component of oil and gas properties pursuant to
the provisions of SFAS 19, Financial Accounting and Reporting by Oil and Gas
Producing Companies. In the event the FASB and SEC staff determine that costs
associated with mineral rights are required to be classified as intangible
assets, a substantial portion of our oil and gas property acquisition costs
since the June 30, 2001 effective date of SFAS Nos. 141 and 142 would be
separately classified on the balance sheets as intangible assets. However, the
results of operations would not be affected since such intangible assets would
continue to be depleted and assessed for impairment in accordance with
successful efforts accounting rules. The classification of oil and gas lease
acquisition costs as intangible assets would not have any impact on our
compliance with covenants under our debt agreements.
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 or greater than the 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 June 30, Six Months Ended June 30,
2003 2002 2003 2002
-------------- -------------- -------------- --------------
(In thousands, except per share data)
Net income as reported............................ $ 7,382 $ 16,566 $ 33,095 $ 18,028
Add:
Stock based employee compensation expense
included in reported net income, net of
related income tax........................... 310 155 494 307
Deduct:
Total stock based employee compensation
expense determined under fair value
based method for all awards, net of related
income tax................................... (565) (297) (1,002) (942)
-------------- -------------- -------------- --------------
Pro forma net income.............................. $ 7,127 $ 16,424 $ 32,587 $ 17,393
============== ============== ============== ==============
Earnings per share:
Basic - as reported.......................... $ 0.38 $ 0.97 $ 1.72 $ 1.06
Basic - pro forma............................ 0.37 0.96 1.69 1.02
Diluted - as reported........................ $ 0.38 $ 0.96 $ 1.70 $ 1.05
Diluted - pro forma.......................... 0.37 0.95 1.68 1.01
9
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 June 30,
--------------------------------------------------------------
2003 2002
---------------------------- -----------------------------
Net Income Shares Net Income Shares
------------- ----------- -------------- -----------
(In thousands)
Earnings - Basic......................... $ 7,382 19,260 $ 16,566 17,079
Effect of dilutive securities
Stock options and restricted stock... -- 247 -- 149
Shares held by benefit trust......... -- -- 29 63
------------- ----------- -------------- -----------
Earnings - Diluted....................... $ 7,382 19,507 $ 16,595 17,291
============= =========== ============== ===========
Six Months Ended June 30,
--------------------------------------------------------------
2003 2002
---------------------------- -----------------------------
Net Income Shares Net Income Shares
------------- ----------- -------------- -----------
(In thousands)
Earnings - Basic......................... $ 33,095 19,230 $ 18,028 17,040
Effect of dilutive securities
Stock options and restricted stock... -- 216 -- 139
Shares held by benefit trust......... -- -- (8) 58
------------- ----------- -------------- -----------
Earnings - Diluted....................... $ 33,095 19,446 $ 18,020 17,237
============= =========== ============== ===========
4. DISCONTINUED OPERATIONS
We sold our Eastern properties in 2002 and we sold our Brea-Olinda and
Union Island oil and gas properties in 2003. Also, in the first quarter 2003,
our Board approved the sale of our Orcutt Hill oil and gas property. The
historical results of operations of these properties are classified as
discontinued operations in our statements of income. The following table
reflects revenue, gain/loss on disposition and pre-tax income for the periods
presented:
Quarter Ended June 30, Six Months Ended June 30,
---------------------------- -----------------------------
2003 2002 2003 2002
------------- ----------- -------------- -----------
(In thousands)
Brea-Olinda
Revenue.............................. $ 1 $ 4,122 $ 3,246 $ 7,475
Gain/(Loss) on disposition........... -- -- -- --
Pre-tax income....................... 244 2,153 2,843 3,981
Union Island
Revenue.............................. 71 241 1,575 798
Gain/(Loss) on disposition........... (20) -- 7,705 --
Pre-tax income....................... 68 28 9,118 378
Eastern Properties
Revenue.............................. -- 1,767 -- 3,278
Gain/(Loss) on disposition........... -- (84) -- (84)
Pre-tax income....................... -- 422 -- 755
Orcutt Hill
Revenue.............................. 2,337 2,263 5,075 4,006
Gain/(Loss) on disposition........... -- -- (5,350) --
Pre-tax income....................... 981 727 (3,081) 722
10
5. ACQUISITION OF ATHANOR RESOURCES, INC.
We acquired Athanor Resources, Inc. ("Athanor") in September 2002 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 acquisition was accounted
for using the purchase method of accounting. In the second quarter of 2003, we
finalized our purchase price allocation, and adjusted certain assets and
liabilities to reflect $2.5 million in insurance proceeds received related to a
pre-acquisition claim. As of June 30, 2003, $17.1 million of goodwill is
reflected on our balance sheet related to Athanor.
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 2002 realized prices, have been adjusted to reflect the
difference between Athanor's historical depletion, depreciation and amortization
and the 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 Six Months Ended
June 30, 2002 June 30, 2002
--------------------- ---------------------
(In thousands, except per share data)
Revenues................................................ $ 83,263 $ 158,524
Income from continuing operations....................... 15,511 16,133
Net income.............................................. 17,490 19,201
Earnings per share
Basic
Income from continuing operations................ $ 0.81 $ 0.85
Net income ...................................... 0.92 1.01
Diluted
Income from continuing operations................ $ 0.81 $ 0.84
Net income ...................................... 0.91 1.00
6. LONG-TERM DEBT
Our long-term debt consists of the following:
June 30, 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 ................................. 100,000 257,210
9 1/2% Senior Subordinated Notes due 2006 ................................. -- 2,367
Bank credit facility (2.36% June 30, 2003, 3.11% December 31, 2002)........ 66,150 28,700
---------------- ---------------
Total debt............................................................. 316,150 438,277
Interest rate swaps - fair value adjustment................................ -- 2,161
Interest rate swaps - termination gain..................................... 15,180 11,673
---------------- ---------------
Long-term debt......................................................... $ 331,330 $ 452,111
================ ===============
In April 2003, we called and completed the redemption of our 9 1/2%
Senior Subordinated Notes due 2006. The notes were redeemed at 101.58% per note.
In June 2003, we called and completed the redemption of $157.2 million of our
9 1/2% Senior Subordinated Notes due 2008 at 104.75% per note. In the second
quarter of 2003, we recorded a $10.9 million loss on early extinguishment of
debt consisting of a $7.5 million call premium and a $3.4 million deferred
financing cost write-off on the notes called. We also terminated our interest
rate swaps and received cash of $4.1 million during the second quarter 2003 (See
Note 7).
11
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. The selling price
for 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 June 30, 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
3rd Qtr.............. 13,500 $ 23.62 WTI 7,500 $ 4.89 Waha
4th Qtr.............. 13,500 23.79 WTI 8,000 4.94 Waha
2004
1st Qtr.............. 14,500 23.76 WTI 16,500 4.93 Waha & Socal
2nd Qtr.............. 13,500 24.03 WTI 14,500 4.65 Waha & Socal
3rd Qtr.............. 11,000 23.64 WTI 10,500 4.50 Waha & Socal
4th Qtr.............. 6,500 23.23 WTI 14,500 4.64 Waha & Socal
2005
Full Year............ 4,500 22.14 WTI
Collars
- --------------------------
2003
Full Year............ 10,000 22.00-28.91 WTI
3rd Qtr.............. 6,000 3.70-4.30 Waha
4th Qtr.............. 6,000 3.70-4.30 Waha
Swaps for Purchases
- --------------------------
2004................. 8,000 3.91 Socal
2005................. 8,000 3.85 Socal
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 and is being amortized as a
periodic reduction in interest expense over the life of the Notes. During the
three months ended June 30, 2003, we amortized $0.3 million as a reduction of
interest expense.
Following the termination of the three interest rate swaps referenced
above, in late August and early November 2002, we entered into two new 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 were
designated as fair value hedges and were reflected as an increase of long-term
debt with a corresponding increase in long-term assets.
12
In May 2003, we terminated our swap transactions relating to these Notes.
As a result of these terminations, we received accrued interest of $0.4 million
and the present value of the swap option of $4.1 million. The gain of $4.1
million on the Notes is reflected as an increase of long-term debt and is being
amortized as a periodic reduction in interest expense over the life of the
Notes. During the three months ended June 30, 2003, we amortized $0.2 million as
a reduction of interest expense. We currently have no interest rate swaps in
place.
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 June 30, 2003 we recorded a
$0.8 million derivative loss and recorded the fair value of the remaining
derivative loss at June 30, 2003 totaling $4.5 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 June 30, 2003
-------------------------------------------------------------------
Oil and Gas Oil and Gas
Domestic Foreign(1) Other(2) Total
------------- -------------- -------------- --------------
(In thousands)
Revenues from external customers............. $ 79,809 $ 14,437 $ 275 $ 94,521
Operating income (loss) before income tax.... 29,386 9,493 (28,052) 10,827
For the Quarter Ended June 30, 2002
-------------------------------------------------------------------
Oil and Gas Oil and Gas
Domestic Foreign(1) Other(2) Total
------------- -------------- -------------- --------------
(In thousands)
Revenues from external customers............. $ 69,205 $ 8,244 $ 42 $ 77,491
Operating income (loss) before income tax.... 39,386 3,800 (18,651) 24,535
For the Six Months Ended June 30, 2003
-------------------------------------------------------------------
Oil and Gas Oil and Gas
Domestic Foreign(1) Other(2) Total
------------- -------------- -------------- --------------
(In thousands)
Revenues from external customers............. $ 166,440 $ 25,918 $ 413 $ 192,771
Operating income (loss) before income tax.... 64,688 15,143 (47,896) 31,935
For the Six Months Ended June 30, 2002
-------------------------------------------------------------------
Oil and Gas Oil and Gas
Domestic Foreign(1) Other(2) Total
------------- -------------- -------------- --------------
(In thousands)
Revenues from external customers............. $ 132,743 $ 15,668 $ 48 $ 148,459
Operating income (loss) before income tax.... 55,696 6,144 (36,681) 25,159
- ------------------------------------------------------------
(1) The timing of Congo crude oil liftings has a significant effect on
foreign results of operations.
(2) Includes corporate income and expenses.
13
9. COMMITMENTS AND CONTINGENCIES
Legal Proceedings and Other Matters
We acquired properties from Unocal and are obligated to make a contingent
payment based on net proceeds received, less certain deductions, on oil sold
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 sales price
that we believe are permitted by the agreement. Application of these deductions
results in no payment due for either calendar year 2001 or 2002. Unocal disputes
this position for both years. Attempts to resolve this issue through mediation
were unsuccessful. We filed suit against Unocal to recover the 2001 payment, and
secure a declaration of the appropriate deduction methodology to be applied for
2002 through 2004 and to recover attorneys' fees. Unocal has answered and filed
a counterclaim claiming breach of contract and anticipatory breach of contract
seeking $16.0 million for 2002 and a declaration of the appropriate deduction
methodology and attorneys' fees. While the outcome of this matter is not
presently determinable, its resolution is not expected to have a significant
impact on our results of operations, financial condition or liquidity.
We have asserted a claim against Torch Energy Advisors for matters
arising out of our former outsourcing arrangement. Among other demands, we have
requested the return of a $2.0 million working capital advance. Torch has
asserted claims for indemnity and payment of certain fees it asserts are owed to
them. These outstanding issues will be arbitrated and are not expected to have a
material impact on our operating results, financial condition or liquidity.
During the second quarter 2003, we entered into a settlement agreement
with Hills for Everyone, a non-profit organization, and Orange County,
California ending litigation challenging the adequacy of the environmental
review of our Tonner Hills real estate project. The settlement did not have a
material impact on the project or our operating results, financial condition or
liquidity.
Contingencies
June 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. Insurance claims relating to the cost of repair and
business interruption (less a 30-day waiting period) were settled in the second
quarter 2003 and we recognized income of $2.3 million.
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. As of June 30, 2003, all outstanding claims
have been settled and compromised. We are awaiting final disposition of certain
non-material insurance claims that have been submitted to our carriers.
Our 1994 acquisition agreement to purchase the two subsidiaries owning
interests in the Yombo field offshore Congo contains a provision for contingent
purchase consideration to be paid by us to the seller if certain conditions are
met. If we recover from sales of production up to an amount greater than all of
our capital and operating costs plus $27 million and which amount increases 27%
annually, then we will pay to the seller out of one-half of our sales proceeds
from the sale of our production, an amount equal to $2.8 million, increased by
7% per year from 1995. We currently estimate that we could reach payout as early
as 2005.
14
Guarantees Related to Assets or Obligations of Third Parties
We have indemnified certain third parties for future environmental
remediation costs that may be incurred for properties that we purchased or
properties that we sold to a third party. The properties may or may not require
environmental remediation and if we are determined to be responsible, our
indemnities may require us, among other matters, to pay for the remediation
costs. We are not able to determine the maximum potential amount, if any, of
future payments that we could be required to make under these indemnifications
primarily due to the following: the indefinite term of the majority of these
indemnities; the unknown extent of possible contamination; the conditional
nature of our responsibility under certain indemnities; uncertainties related to
the timing of the remediation work; possible changes in laws governing the
remediation process; the unknown number of claims that may be made and changes
in remediation technology.
We have performance obligations in the ordinary course of business that
are secured by surety bonds or letters of credit. These surety bonds and letters
of credit are issued by financial institutions and are required to be reimbursed
if drawn upon. At June 30, 2003, we had surety bonds of $39.7 million and
letters of credit of $2.2 million.
In the ordinary course of business, we have provided indemnifications and
guarantees that are not explicitly defined whose terms range in duration. We do
not believe that these will have a material effect on our financial position,
results of operation or cash flows.
15
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our discussion and analysis of our financial condition and results of
operations is based upon our consolidated financial statements which have been
prepared in accordance with accounting principles generally accepted in the
United States of America ("GAAP"). The preparation of our financial statements
requires us to make estimates and judgments that affect the reported amount of
assets, liabilities, revenues and expenses. We believe the following critical
accounting policies reflect our significant estimates and judgments used in the
preparation of our financial statements:
Revenue Recognition. Crude oil and natural gas revenue is recognized when
title passes to the purchaser. We use the entitlement method for recording sales
of crude oil and natural gas from producing wells. Under the entitlement method,
revenue is recorded based on our net revenue interest in production. Deliveries
of crude oil and natural gas in excess of our net revenue interests are recorded
as liabilities and under-deliveries are recorded as assets. Production
imbalances are recorded at the lower of the sales price in effect at the time of
production or the current market value. Substantially all such amounts are
anticipated to be settled with production in future periods.
Successful Efforts Accounting. We account for our crude oil and natural
gas operations using the successful efforts method of accounting. Under this
method of accounting, all costs associated with oil and gas lease acquisition
costs, successful exploratory wells and all development wells are capitalized
and amortized on a unit-of-production basis over the remaining life of proved
developed reserves and proved reserves. When a proved property is sold, ceases
to produce or is abandoned, a gain or loss is recognized. When an entire
interest in an unproved property is sold for cash or cash equivalent, a gain or
loss is recognized, taking into consideration any recorded impairment. When a
partial interest in an unproved property is sold, the amount received is treated
as a reduction of the cost of the interest retained. Unproved leasehold costs
are capitalized pending the results of exploration efforts. Exploration costs,
including geological and geophysical expenses, exploratory dry holes and delay
rentals, are charged to expense when incurred.
Proved Reserve Estimates. There are uncertainties inherent in estimating
crude oil and natural gas reserve quantities, projecting future production rates
and projecting the timing of future development expenditures. In addition,
reserve estimates of new discoveries are more imprecise than those of properties
with a production history. Accordingly, these estimates are subject to change as
additional information becomes available. Proved reserves are the estimated
quantities of crude oil, condensate and natural gas that geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions at the end of the respective years. Proved developed reserves are
those reserves expected to be recovered through existing equipment and operating
methods.
Impairment of Proved Oil and Gas Properties. We review our proved
properties when management determines that events or circumstances indicate that
the recorded carrying value of the properties may not be recoverable. If the
carrying amount of an asset exceeds the sum of the undiscounted estimated future
net cash flows, we recognize an impairment equal to the difference between the
carrying value and the fair value of the asset which is estimated to be the
expected present value of future net cash flows from proved reserves, utilizing
a risk-free rate of return.
Impairment of Unproved Oil and Gas Properties. 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.
Impairment of Goodwill. Goodwill of a reporting unit is tested for
impairment annually in the fourth quarter, and also at interim dates upon the
occurrence of significant events. The fair value of each reporting unit that has
goodwill is determined and compared to the book value of the reporting unit. If
the fair value of the reporting unit is less than the book value, including
goodwill, the fair value of the reporting unit's individual assets and
liabilities is deducted from the fair value of the reporting unit. This
difference represents the implied fair value of goodwill, which is compared to
the book value of the reporting unit's goodwill. We recognize an impairment of
the excess of the book value of goodwill over the implied fair value of
goodwill.
16
Asset Retirement Obligations. The computation of asset retirement
obligations was prepared in accordance with SFAS No. 143, Accounting for Asset
Retirement Obligation, which requires us to record the fair value of liabilities
for retirement obligations of long-lived assets. Our asset retirement
obligations arise from the plugging and abandonment liabilities for our oil and
gas wells and offshore platform facilities. We estimated our liability based on
the best information available to us at this time. Revisions to the liability
could occur due to changes in the timing and actual plugging and abandonment
costs.
Derivative Financial Instruments and Price Risk Management Activities. We
use price risk management activities to manage non-trading market risks. We use
derivative financial instruments such as swaps, collars and put options to hedge
the impact market price risk exposures on our crude oil and natural gas
production, natural gas purchases and to mitigate our exposure to interest rate
risk. We account for our derivatives under SFAS 133, Accounting for Derivative
Instruments and Hedging Activities, and have elected to designate derivative
instruments that qualify for hedge accounting as cash flow hedges for commodity
related contracts and fair value hedges for interest rate contracts. Derivatives
that do not qualify for hedge accounting are carried on the balance sheet at
fair value, and changes in its fair value are recognized in earnings.
Stock-Based Compensation. We account for stock compensation plans under
the intrinsic value method of Accounting Principles Board Opinion 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. We disclose in both annual and
interim financial statements the effect of reported results had the stock based
compensation been determined based on fair value at the date of grant and
expensed.
Income Taxes. Deferred income taxes are accounted for under the asset and
liability method of accounting for income taxes. Under this method, deferred
income taxes are recognized for the tax consequences of temporary differences by
applying enacted statutory tax rates applicable to future years to differences
between the financial statement carrying amounts and the tax basis of existing
assets and liabilities. The effect on deferred taxes of a change in tax rates is
recognized in income in the period the change occurs.
RESULTS OF OPERATIONS
Our results of operations are significantly affected by fluctuations in
oil and gas prices. We sold our Brea-Olinda field, Union Island field, Eastern
properties and our Orcutt Hill field is held for sale. The results of operations
of these properties are classified as discontinued operations in our financial
statements. The following table reflects our production and average prices for
oil and natural gas excluding our discontinued operations for all periods
presented:
Quarter Ended Six Months Ended
June 30, June 30,
--------------------------------- ---------------------------------
2003 2002 2003 2002
-------------- -------------- --------------- --------------
Crude Oil and Liquids
Sales Volumes (MBbls/day)
Domestic ..................... 37.1 35.9 37.1 36.8
Foreign ...................... 5.0 5.4 5.0 5.2
-------------- -------------- --------------- --------------
Total .................... 42.1 41.3 42.1 42.0
============== ============== =============== ==============
Sales Prices ($/Bbl)
Unhedged ..................... $ 22.68 $ 19.05 $ 24.09 $ 17.39
Hedged ....................... 21.09 18.47 21.46 17.72
Revenues ($/thousands)
Domestic ..................... $ 72,480 $ 63,675 $ 157,751 $ 117,012
Foreign ...................... 14,437 8,244 25,918 15,668
Marketing Fees ............... (1) (253) (4) (446)
Hedging ...................... (6,098) (2,160) (20,045) 2,523
-------------- -------------- --------------- --------------
Total .................... $ 80,818 $ 69,506 $ 163,620 $ 134,757
============== ============== =============== ==============
17
Quarter Ended Six Months Ended
June 30, June 30,
--------------------------------- ---------------------------------
2003 2002 2003 2002
-------------- -------------- --------------- --------------
Natural Gas
Sales Volumes (MMcf/day)
Domestic .................... 36.4 28.1 37.9 28.3
============== ============== =============== ==============
Sales Prices ($/Mcf)
Unhedged .................... $ 4.26 $ 3.10 $ 4.54 $ 2.67
Hedged....................... 4.06 3.10 4.19 2.67
Revenues ($/thousands)
Domestic .................... $ 14,250 $ 8,092 $ 31,356 $ 13,891
Marketing Fees .............. (153) (149) (246) (237)
Hedging...................... (669) -- (2,372) --
-------------- -------------- --------------- --------------
Total ................... $ 13,428 $ 7,943 $ 28,738 $ 13,654
============== ============== =============== ==============
QUARTER ENDED JUNE 30, 2003 COMPARED TO QUARTER ENDED JUNE 30, 2002
We had net income of $7.4 million, or $0.38 per diluted share and income
from continuing operations was $6.6 million, or $0.34 per diluted share for the
quarter ended June 30, 2003 as compared to net income of $16.6 million, or $0.96
per diluted share and income from continuing operations of $14.6 million, or
$0.84 per diluted share in the same period of 2002. Income from continuing
operations is discussed below.
Revenues
Oil and Gas Revenues. Oil and gas revenues increased 22% to $94.2 million
for the three months ended June 30, 2003 from $77.4 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 increased to 42.1 MBbls/day for the three months
ended June 30, 2003 compared to 41.3 MBbls/day in the same period of 2002
primarily due to higher production from the Pakenham field which was acquired in
September 2002 and the acquisition of an additional interest in the Point
Pedernales field offshore California. The realized oil price for the three
months ended June 30, 2003 was $21.09 per Bbl, an increase of $2.62 per Bbl from
the same period in 2002. We had crude oil hedging losses of $6.1 million in the
three months ended June 30, 2003 compared to hedging losses of $2.2 million in
same period of 2002. Natural gas production averaged 36.4 MMcf per day for the
three months ended June 30, 2003, an increase of 8.3 MMcf per day from the same
period of 2002. The Pakenham field which was acquired in September 2002 averaged
14.8 MMcf per day during the three months ended June 30, 2003 and was partially
offset by lower production onshore and offshore California of 6.6 MMcf per day
due to the watering out of wells on our Pitas Point offshore property (3.9 MMcf
per day) and mechanical downtime and normal declines on other California
properties. The realized natural gas price for the three months ended June 30,
2003 increased 31% to $4.06 per Mcf, including a $0.20 per Mcf hedging loss,
compared to $3.10 per Mcf from the comparable period in 2002 that had no gas
hedged.
Costs and Expenses
Costs and Expenses. Lease operating expense ("LOE") for the three months
ended June 30, 2003 totaled $42.1 million, as compared to $32.4 million for the
2002 period. The increased LOE is due to higher steam costs in our onshore
California operations (principally due to higher natural gas prices for gas
purchased), higher workover and major maintenance expense in our offshore
California operations and field costs in our Pakenham field which was purchased
in 2002 and the acquisition of an additional interest in Point Pedernales.
Although depletion, depreciation, amortization and accretion ("DD&A") of $17.7
million for the three months ended June 30, 2003, was comparable to the same
period of 2002, the DD&A rate was $4.04 per BOE in the 2003 period compared to
$4.17 per BOE in 2002. General and administrative expense of $6.3 million in
2003 was $0.9 million lower than the comparable period in 2002 primarily due to
lower outsourcing costs in 2003. The gain on disposition of properties was $4.5
million for the three months ended June 30, 2003 as compared to a $15.3 million
gain in 2002. The 2003 gain was due to the release of escrow related to the sale
of properties in 2001. In
18
2002, under the terms of a settlement agreement with ExxonMobil, we conveyed to
them our interest in the Santa Ynez Unit, our non-consent interest in the
adjacent Pescado field and relinquished our right to participate in the Sacate
field and recorded a $14.7 million gain related to the sale of this unproved
property.
Derivative Gain (Loss). Our derivative loss for the quarter ended June
30, 2003 was $0.8 million compared to a loss of $0.2 million in the same period
of 2002. The derivative loss is comprised of a loss on our mark-to-market
derivatives and ineffectiveness of our hedges.
Interest Expense. Interest expense was $9.0 million for the three months
ended June 30, 2003 compared to interest expense of $9.2 million in the same
period of 2002. Lower interest expense on the line of credit of $0.5 million,
lower interest expense of $0.4 million on the 9 1/2% Notes which were redeemed
and lower facility fees of $0.2 million were partially offset by a lower benefit
on the interest rate swaps of $1.0 million which was due to the termination of
the remaining swaps in the second quarter 2003.
Loss on Early Extinguishment of Debt. We redeemed $157.2 million of our
9 1/2% Notes due 2008 and the remaining $2.4 million of our 9 1/2% Notes due
2006 during the three months ended June 30, 2003. In connection with the
redemptions, we paid a premium of $7.5 million and wrote off $ 3.4 million of
deferred financing costs.
Dividends. Dividends on the TECONS were $1.7 million in both the three
months ended June 30, 2003 and 2002. The TECONS pay dividends at a rate of
5.75%.
Income Tax. We had income tax expense of $4.2 million including current
tax of $0.6 million for the three months ended June 30, 2003, compared to an
expense of $9.9 million in the prior year period which had no current tax. The
current tax relates to California State income tax which deferred the use of net
operating losses for two years and Federal income tax. Our effective income tax
rate was 38.9% in 2003 and 40.5% in 2002.
Discontinued Operations. We had income from discontinued operations of
$0.8 million for the three months ended June 30, 2003 compared to income of $2.0
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. In 2002 the income from
discontinued operations consists of after-tax operating income from our Eastern
fields which were sold in 2002 and operating income from the Brea-Olinda, Union
Island and Orcutt Hill properties.
YEAR TO DATE JUNE 30, 2003 COMPARED TO YEAR TO DATE JUNE 30, 2002
We had net income of $33.1 million, or $1.70 per diluted share and income
from continuing operations of $19.3 million, or $0.99 per diluted share for the
six months ended June 30, 2003 as compared to net income of $18.0 million, or
$1.05 per diluted share and income from continuing operations of $15.0 million,
or $0.87 per diluted share in the same period of 2002. Income from continuing
operations is discussed below.
Revenues
Oil and Gas Revenues. Oil and gas revenues increased 30% to $192.4
million for the six months ended June 30, 2003 from $148.4 million in the same
period of 2002 due to significantly 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 six
months ended June 30, 2003 compared to 42.0 MBbls/day in the same period of
2002. Higher production from the Pakenham field which was acquired in September
2002 and the acquisition of an additional interest in Point Pedernales were
partially offset by lower production offshore California due to mechanical
downtime. The realized oil price for the six months ended June 30, 2003 was
$21.46 per Bbl, an increase of $3.74 per Bbl from the same period in 2002. We
had hedging losses of $20.0 million in the six months ended June 30, 2003
compared to hedging gains of $2.5 million in same period of 2002. Natural gas
production averaged 37.9 MMcf per day for the six months ended June 30, 2003, an
increase of 9.6 MMcf per day from the same period of 2002. The Pakenham field
which was acquired in September 2002 averaged 15.6 MMcf per day during the six
months ended June 30, 2003 and was partially offset by production declines at
Pitas Point and mechanical downtime and normal declines onshore California. The
realized natural gas price for the six months ended June 30, 2003 was $4.19 per
Mcf, including a $0.35 per Mcf hedging loss, compared to $2.67 per Mcf from the
comparable period in 2002 which had no production hedged.
19
Costs and Expenses
Costs and Expenses. LOE for the six months ended June 30, 2003 totaled
$81.4 million, as compared to $67.0 million for the 2002 period. The increased
LOE is due to higher steam costs in our onshore California operations, field
costs from our Pakenham field which was acquired in 2002 and the acquisition of
an additional interest in our Point Pedernales property. Exploration costs were
$1.4 million in the six months ended June 30, 2003 compared to $1.5 million in
the same period of 2002. Exploration costs in 2003 included the dry hole cost of
Chott Fejaj in Tunisia while the 2002 costs were primarily seismic acquisitions.
DD&A was $35.1 million for the six months ended June 30, 2003, compared to $34.7
million in the same period of 2002. The DD&A rate was $4.00 per BOE in the 2003
period compared to $4.10 per BOE in 2002. General and administrative expense of
$13.1 million in 2003 was $0.2 million lower than the comparable period in 2002
due to lower outsourcing costs. The gain on disposition of properties was $4.5
million for the six months ended June 30, 2003 as compared to a $15.3 million
gain in 2002. The 2003 gain was due to the release of escrow related to the sale
of properties in 2001. In 2002, under the terms of a settlement agreement with
ExxonMobil, we conveyed to them our interest in the Santa Ynez Unit, our
non-consent interest in the adjacent Pescado field and relinquished our right to
participate in the Sacate field and recorded a $14.7 million gain related to the
sale of this unproved property.
Derivative Gain (Loss). Our derivative loss for the six months ended June
30, 2003 was $1.7 million compared to a loss of $0.9 million in the same period
of 2002. The derivative loss is comprised of a loss on our mark-to-market
derivatives and ineffectiveness of our hedges.
Interest Expense. Interest expense was $18.4 million for the six months
ended June 30, 2003 compared to interest expense of $18.2 million in the same
period of 2002. Lower interest expense on our line of credit of $0.8 million,
lower interest expense of $0.4 million on the 9 1/2% Notes which were redeemed
and lower facility fees of $0.4 million were more than offset by a lower benefit
on the interest rate swaps of $1.9 million which was due to fewer swaps and a
lower benefit on interest rate swaps which were terminated in the second quarter
2003.
Loss on Early Extinguishment of Debt. In 2003 we redeemed $157.2 million
of our 9 1/2% Notes due 2008 and $2.4 million of our 9 1/2% Notes due 2006. In
connection with the redemptions, we paid a premium of $7.5 million and wrote off
$3.4 million of deferred financing costs.
Dividends. Dividends on the TECONS were $3.3 million in both the six
months ended June 30, 2003 and 2002. The TECONS pay dividends at a rate of
5.75%.
Income Tax. We had income tax expense of $12.7 million including current
tax of $2.1 million for the six months ended June 30, 2003, compared to an
expense of $10.2 million in the prior year period which had no current tax. The
current tax relates to California State income tax which deferred the use of net
operating losses for two years and Federal income tax. Our effective income tax
rate was 39.6% in 2003 and 40.5% in 2002.
Discontinued Operations. We had income from discontinued operations of
$5.3 million for the six months ended June 30, 2003 compared to income of $3.1
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 and a $5.4 million loss in
connection with writing down the Orcutt Hill property to the estimated fair
value less our costs to sell the property. In 2002 the income from discontinued
operations consists of after-tax operating income from our Eastern fields which
were sold in 2002 and operating income from the Brea-Olinda, Union Island and
Orcutt Hill properties.
Cumulative Effect of Change in Accounting Principle. In January 2003, we
adopted 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).
20
CAPITAL RESOURCES AND LIQUIDITY
Major sources of cash in the first half of 2003 were net cash provided by
operating activities of $85.1 million, proceeds from the sale of properties of
$69.9 million, borrowings under the bank credit agreement of $37.5 million, and
$1.8 million of other investing activities. We used this cash, along with cash
on hand at the beginning of the year, to fund capital expenditures on our oil
and gas and other properties of $32.6 million and to redeem $159.6 million of
our outstanding senior subordinated notes, plus a $7.5 million call premium. The
redemption of the notes will result in lower cash interest expense on our 9 1/2%
notes of $15.1 million per year.
Current assets decreased from $157.6 million at December 31, 2002 to
$118.8 million at June 30, 2003 principally due to the sale of our Brea-Olinda
property which was sold in the first quarter and removed from assets held for
sale. Accounts receivable rose $7.7 million due to a crude oil lifting in Congo
that occurred in June 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 $200.0 million borrowing
base under our Credit Agreement. Under the most restrictive covenant, $131.6
million was available at June 30, 2003 and we had $66.2 million outstanding. We
have letters of credit outstanding of $2.2 million under our Credit Agreement.
CONTINGENCIES AND OTHER MATTERS
See Item 1, Financial Statements, Note 9, which is incorporated herein by
reference.
NEW ACCOUNTING PRONOUNCEMENTS
See Item 1, Financial Statements, Note 1, which is incorporated herein by
reference.
21
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.
22
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 June 30, 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
3rd Qtr............ 13,500 $ 23.62 WTI 7,500 $ 4.89 Waha
4th Qtr............ 13,500 23.79 WTI 8,000 4.94 Waha
2004
1st Qtr............ 14,500 23.76 WTI 16,500 4.93 Waha & Socal
2nd Qtr............ 13,500 24.03 WTI 14,500 4.65 Waha & Socal
3rd Qtr............ 11,000 23.64 WTI 10,500 4.50 Waha & Socal
4th Qtr............ 6,500 23.23 WTI 14,500 4.64 Waha & Socal
2005
Full Year.......... 4,500 22.14 WTI
Collars
- ------------------------
2003
Full Year.......... 10,000 22.00-28.91 WTI
3rd Qtr............ 6,000 3.70-4.30 Waha
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 June 30, 2003, we entered into the following cash flow
hedges:
Crude Oil Natural Gas
-------------------------------------------- ------------------------------------------------
Bbls / day $ / Bbl Index MMbtu/day $/MMbtu Index
------------ --------------- --------- --------------- ----------- --------------
Swaps for Sales
- --------------------------
2004
4th Qtr.............. 2,000 25.50 WTI
2005
1st Qtr.............. 5,000 25.20 WTI 3,500 $ 5.00 Socal
23
ITEM 4. CONTROLS AND PROCEDURES
The term "disclosure controls and procedures" is defined in Rules
13a-15(e) and 15d-15(e) 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 or submits under the Exchange Act is recorded, processed,
summarized and reported within the time periods specified by the Securities and
Exchange Commission. Our management, including our Chief Executive Officer and
Chief Financial Officer, has evaluated the effectiveness of our disclosure
controls and procedures as of the end of the period covered by this quarterly
report. Based upon that evaluation, our Chief Executive Officer and Chief
Financial Officer have concluded that our disclosure controls and procedures
were effective as of the end of the period covered by this quarterly report.
24
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
We held our Annual Meeting of Stockholders on May 21, 2003. Proposals
presented for a stockholders' vote included the election of eight directors, the
ratification of KPMG LLP as independent auditors for 2003 and the ratification
of certain stock incentive plans.
Election of Board of Directors
Each of the eight directors was elected with the following results:
For Withheld
----------------------- ------------------------
Isaac Arnold, Jr.......... 17,145,843 343,659
Charles M. Elson.......... 17,145,843 343,659
Robert L. Gerry III....... 13,949,949 3,539,553
J. Frank Haasbeek......... 17,146,697 342,805
James T. Jongebloed....... 16,381,793 1,107,709
James L. Payne............ 17,147,093 342,409
Gary R. Petersen.......... 17,147,093 342,409
Sheryl K. Pressler........ 17,147,253 342,409
Ratification of Appointment of Independent Auditors
The appointment of KPMG LLP as our independent auditors for 2003 was
ratified with the following results:
For Against Abstain
-------------- --------------- --------------
KPMG LLP.................. 16,668,000 808,407 13,095
Ratification of Certain Stock Incentive Plans
Certain stock incentive plans approved by the board of directors were
ratified and approved with the following results:
For Against Abstain
-------------- --------------- --------------
Stock Incentive Plan...... 12,552,907 4,458,887 507,708
25
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) EXHIBITS:
31.1 Certification of Chief Executive Officer of Nuevo Energy Company pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002
31.2 Certification of Chief Financial Officer of Nuevo Energy Company pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002
32.1 Certification of Chief Executive Officer of Nuevo Energy Company pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002
32.2 Certification of Chief Financial Officer of Nuevo Energy Company pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002
(b) REPORTS ON FORM 8-K:
DATE EVENT REPORTED
--------------------- ---------------------------------------------------------------------------
May 14, 2003 Press release announcing first quarter 2003 earnings
May 28, 2003 Press release announcing the partial redemption of the 9 1/2% Senior
Subordinated Notes
June 24, 2003 Press release announcing the completion of the partial redemption of the
9 1/2% Senior Subordinated Notes
August 12, 2003 Press release announcing second quarter 2003 earnings
26
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: August 13, 2003 By: /s/ James L. Payne
------------------------- -------------------------------
James L. Payne
Chairman, President and
Chief Executive Officer
Date: August 13, 2003 By: /s/ Janet F. Clark
------------------------- -------------------------------
Janet F. Clark
Senior Vice President and
Chief Financial Officer
27
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
------- -----------
31.1 Certification of Chief Executive Officer of Nuevo Energy Company pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002
31.2 Certification of Chief Financial Officer of Nuevo Energy Company pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002
32.1 Certification of Chief Executive Officer of Nuevo Energy Company pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002
32.2 Certification of Chief Financial Officer of Nuevo Energy Company pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002