<PAGE>
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1998
[_] 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: 0-9808
PLAINS RESOURCES INC.
(Exact name of registrant as specified in its charter)
DELAWARE 13-2898764
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
500 DALLAS STREET
HOUSTON, TEXAS 77002
(Address of principal executive offices)
(Zip Code)
(713) 654-1414
(Registrant's telephone number, including area code)
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
----- -----
16,868,138 shares of common stock $.10 par value, issued and outstanding at
November 9,1998.
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PLAINS RESOURCES INC. AND SUBSIDIARIES
TABLE OF CONTENTS
- -------------------------------------------------------------------------------
PART I. FINANCIAL INFORMATION
CONSOLIDATED FINANCIAL STATEMENTS:
Consolidated Balance Sheets:
September 30, 1998 and December 31, 1997............................. 3
Consolidated Statements of Income:
For the three and nine months ended September 30, 1998 and 1997...... 4
Consolidated Statements of Cash Flows:
For the nine months ended September 30, 1998 and 1997................ 5
Notes to Consolidated Financial Statements............................. 6
MANAGEMENT'S DISCUSSION AND ANALYSIS................................... 11
PART II. OTHER INFORMATION............................................. 26
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<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (in thousands, except share data)
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------
September 30, December 31,
1998 1997
------------- ------------
(unaudited)
ASSETS
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents $ 7,887 $ 3,714
Accounts receivable 113,828 99,597
Inventory 29,020 22,802
Prepaids and other 506 667
--------------- ---------------
Total current assets 151,241 126,780
--------------- ---------------
PROPERTY AND EQUIPMENT
Oil and natural gas properties -- full cost method:
Subject to amortization 562,575 498,038
Not subject to amortization 55,979 52,024
Crude oil pipeline, gathering and terminal assets 432,462 35,451
Other property and equipment 8,813 8,074
--------------- ---------------
1,059,829 593,587
Less allowance for depreciation, depletion and amortization (201,139) (180,279)
--------------- ---------------
858,690 413,308
--------------- ---------------
OTHER ASSETS 22,185 16,731
--------------- ---------------
$ 1,032,116 $ 556,819
=============== ===============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and other current liabilities $ 134,675 $ 102,663
Interest payable 6,569 6,601
Royalties payable 3,922 5,016
Notes payable and other current obligations 12,011 18,511
--------------- ---------------
Total current liabilities 157,177 132,791
BANK DEBT 439,500 80,000
SUBORDINATED DEBT 202,488 202,661
OTHER LONG-TERM DEBT 2,556 3,067
OTHER LONG-TERM LIABILITIES 5,652 5,107
--------------- ---------------
807,373 423,626
--------------- ---------------
SERIES E CUMULATIVE CONVERTIBLE PREFERRED STOCK,
STATED AT LIQUIDATION PREFERENCE 85,000 --
--------------- ---------------
NON-REDEEMABLE PREFERRED STOCK, COMMON STOCK
AND OTHER STOCKHOLDERS' EQUITY
Series D Cumulative Convertible Preferred Stock, $1.00 par value,
46,600 shares authorized, issued and outstanding, net of
discount of $1,680,000 and $2,629,000 at September 30,
1998, and December 31, 1997, respectively 21,620 20,671
Common stock, $.10 par value, 50,000,000 shares authorized; issued
and outstanding, 16,852,233 shares at September 30, 1998, and
16,703,074 shares at December 31, 1997 1,685 1,670
Additional paid-in capital 124,360 122,887
Accumulated deficit (7,922) (12,035)
--------------- ---------------
139,743 133,193
--------------- ---------------
$ 1,032,116 $ 556,819
=============== ===============
</TABLE>
See notes to consolidated financial statements.
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PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (unaudited) (in thousands, except per share
data)
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------------ ----------------------------
1998 1997 1998 1997
----------- ------------- ------------ -----------
<S> <C> <C> <C> <C>
REVENUE
Oil and natural gas sales $ 26,008 $ 27,265 $ 77,719 $ 79,829
Marketing, transportation, storage 367,591 193,318 698,274 536,332
and terminalling revenues
Interest and other income 120 77 739 223
-------- -------- -------- --------
393,719 220,660 776,732 616,384
-------- -------- -------- --------
EXPENSES
Production expenses 12,931 12,099 38,604 33,064
Marketing, transportation, storage
and terminalling expenses 353,677 189,994 675,160 527,478
General and administrative 2,883 1,990 7,696 6,205
Depreciation, depletion and amortization 8,352 5,993 21,945 17,257
Interest expense 11,519 5,986 24,385 15,877
-------- -------- -------- --------
389,362 216,062 767,790 599,881
-------- -------- -------- --------
Income before income taxes 4,357 4,598 8,942 16,503
Income tax expense (benefit):
Current (11) 80 11 290
Deferred 743 1,759 2,457 6,311
-------- -------- -------- --------
NET INCOME 3,625 2,759 6,474 9,902
Less: cumulative preferred stock dividends 1,733 -- 2,361 --
-------- -------- -------- --------
NET INCOME AVAILABLE TO
COMMON STOCKHOLDERS $ 1,892 $ 2,759 $ 4,113 $ 9,902
======== ======== ======== ========
Earnings per share:
Basic $ 0.11 $ 0.17 $ 0.24 $ 0.60
======== ======== ======== ========
Diluted $ 0.10 $ 0.15 $ 0.22 $ 0.55
======== ======== ======== ========
</TABLE>
See notes to consolidated financial statements.
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PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) (in thousands)
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------------
Nine months Ended
September 30,
-----------------------------------------------
1998 1997
------------------- --------------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 6,474 $ 9,902
Items not affecting cash flows from operating activities:
Depreciation, depletion and amortization 21,945 17,257
Deferred income taxes 2,457 6,311
Other noncash items 72 202
Change in assets and liabilities resulting from operating activities:
Accounts receivable 38,271 (827)
Inventory (5,557) (28,682)
Prepaids and other (893) (426)
Accounts payable and other current liabilities (26,753) (4,042)
Interest payable 174 (3,022)
Royalties payable (677) 469
----------- ----------
Net cash provided by (used in) operating activities 35,513 (2,858)
----------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition (see Note 2):
Payment for acquisition of pipeline and related assets (392,393) --
Payment for working capital (excluding cash received of $7,481) (1,498) --
Payment for acquisition, exploration and development costs (62,674) (74,818)
Payment for additions to other property and assets (5,763) (3,840)
----------- ----------
Net cash used in investing activities (462,328) (78,658)
----------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt 471,160 221,604
Proceeds from short-term debt 28,800 25,000
Proceeds from issuance of preferred stock 85,000 --
Principal payments of long-term debt (111,660) (164,500)
Principal payments of short-term debt (35,300) --
Debt issue costs incurred in connection with acquisition (see Note 2) (6,138) --
Other (874) (20)
----------- ----------
Net cash provided by financing activities 430,988 82,084
----------- ----------
Net increase in cash and cash equivalents 4,173 568
Cash and cash equivalents, beginning of period 3,714 2,517
----------- ----------
Cash and cash equivalents, end of period $ 7,887 $ 3,085
=========== ==========
</TABLE>
See notes to consolidated financial statements.
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PLAINS RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1998
(UNAUDITED)
Note 1 -- Accounting Policies
The accompanying unaudited consolidated financial statements have been prepared
in accordance with the instructions to interim financial reporting as prescribed
by the Securities and Exchange Commission ("SEC"). For further information,
refer to the consolidated financial statements and notes thereto included in the
Company's Annual Report on Form 10-K for the year ended December 31, 1997, filed
with the SEC.
All material adjustments consisting only of normal recurring adjustments which,
in the opinion of management, were necessary for a fair statement of the results
for the interim periods, have been reflected. Certain reclassifications have
been made to the prior year statements to conform with the current year
presentation. The Company evaluates the capitalized costs of its oil and natural
gas properties on an ongoing basis and has utilized the most recently available
information to estimate its reserves at September 30, 1998, in order to
determine the realizability of such capitalized costs. Future events, including
drilling activities, product prices and operating costs, may affect future
estimates of such reserves.
Note 2 -- Acquisition
On July 30, 1998, Plains All American Inc. ("PAAI"), a wholly owned unrestricted
subsidiary of the Company, as defined in the indentures for the Company's $200
million 10.25% Senior Subordinated Notes (the "Indentures"), acquired all of the
outstanding capital stock of the All American Pipeline Company, Celeron
Gathering Corporation and Celeron Trading & Transportation Company (collectively
the "Celeron Companies") from Wingfoot Ventures Seven, Inc., a wholly-owned
subsidiary of The Goodyear Tire & Rubber Company ("Goodyear") for approximately
$400 million, including transaction costs. The principal assets of the entities
acquired include the All American Pipeline System, a 1,233-mile crude oil
pipeline extending from California to Texas, and a 45-mile crude oil gathering
system in the San Joaquin Valley of California, as well as other assets related
to such operations.
Financing for the acquisition was provided through (i) PAAI's $325 million,
limited recourse bank facility with ING (U.S.) Capital Corporation, BankBoston,
N.A. and other lenders (the "PAAI Credit Facility") (see Note 4) and (ii) an
approximate $114 million capital contribution to PAAI by the Company.
Approximately $29 million of such capital contribution was funded by cash flow
and the Company's revolving credit facility (the "Revolving Credit Facility")
and the remaining $85 million was provided by a privately placed issuance of the
Company's Series E Cumulative Convertible Preferred Stock (the "Series E
Preferred Stock") (see Note 3).
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The assets, liabilities and results of operations of the Celeron Companies are
included in the Consolidated Financial Statements of the Company effective
July 30, 1998. The following unaudited pro forma information is presented to
show pro forma revenues, net income and earnings per share as if the acquisition
occurred on January 1, 1997.
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
------------------------------------------
1998 1997
------------------ --------------------
<S> <C> <C>
(in thousands)
Revenue $ 1,214,386 $ 1,362,954
============== =============
Net income $ 13,426 $ 26,989
============== =============
Earnings per share:
Basic $ 0.38 $ 1.26
============== =============
Diluted $ 0.35 $ 1.16
============== =============
</TABLE>
The acquisition was accounted for utilizing the purchase method of accounting
and the purchase price was allocated in accordance with Accounting Principles
Board opinion No. 16 as follows (in thousands):
<TABLE>
<S> <C>
Crude oil pipeline, gathering and terminal assets $ 392,393
Oil and natural gas properties 4,922
Other assets (debt issue costs) 6,138
Net working capital items 8,979
---------
$ 412,432
Deferred tax liability (4,922)
---------
Cash paid $ 407,510
=========
</TABLE>
The increase in oil and natural gas properties subject to amortization and
deferred tax liability of approximately $4.9 million relates to increased state
deferred taxes owed by the Company as a direct result of the acquisition. Such
increase was allocated to oil and natural gas properties because it primarily
relates to the temporary differences between the book and tax bases of the
Company's oil and natural gas properties.
NOTE 3 -- PREFERRED STOCK
On July 29, 1998, the Company sold in a private placement 170,000 shares of its
Series E Preferred Stock for $85 million. Each share of the Series E Preferred
Stock has a stated value of $500 per share and bears a dividend of 9.5% per
annum. Dividends are payable semi-annually in either cash or additional shares
of Series E Preferred Stock at the Company's option and are cumulative from the
date of issue. Each share of Series E Preferred Stock is convertible into 27.78
shares of the Company's common stock ("Common Stock") (an initial effective
conversion price of $18.00 per share) and in certain circumstances may be
converted at the Company's option into Common Stock if the average trading price
for any thirty-day trading period is equal to or greater than $21.60 per share.
The Series E Preferred Stock is redeemable at the option of the Company after
March 31, 1999, at 110% of stated value and at declining amounts thereafter. If
not previously redeemed or converted, the Series E Preferred Stock is required
to be redeemed in 2012.
Proceeds from the Series E Preferred Stock were used to fund a portion of the
Company's capital contribution to PAAI to acquire all of the outstanding capital
stock of the Celeron Companies (see Note 2).
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On October 1, 1998, the Company paid a dividend on the Series E Preferred Stock
for the period from July 29, 1998 through September 30, 1998. The dividend
amount of approximately $1.4 million was paid by issuing 2,824 additional shares
of the Series E Preferred Stock. After payment of such dividend, there were
172,824 shares of the Series E Preferred Stock outstanding with a liquidation
value of approximately $86.4 million.
NOTE 4 -- DEBT
Plains All American Inc. Credit Facility
On July 30, 1998, PAAI borrowed $300 million under the PAAI Credit Facility.
Such proceeds were used to acquire all of the outstanding capital stock of the
Celeron Companies from Goodyear and to provide initial working capital (see Note
2). At September 30, 1998, the Company had $285 million outstanding under the
PAAI Credit Facility.
The PAAI Credit Facility is guaranteed by the Celeron Companies and is secured
by the assets of PAAI and the Celeron Companies, including all pipelines
(including associated linefill), gathering lines, accounts receivable, inventory
and the capital stock of the Celeron Companies. The PAAI Credit Facility
consists of (i) a $100 million reducing, revolving line of credit with a $30
million sub-limit for letters of credit ("Tranche A") and (ii) a $225 million
non-amortizing term loan ("Tranche B"). PAAI incurs a commitment fee of 0.5% per
annum on the unused portion of Tranche A. The commitment for Tranche A reduces
in twenty-four equal quarterly amounts commencing September 30, 1998, with final
maturity on June 30, 2004. Tranche B of the PAAI Credit Facility is repayable at
maturity on June 30, 2005. Prepayment of principal on Tranche B is subject to a
penalty of 1% on amounts prepaid prior to December 31, 1998, and 0.5% thereafter
through June 30, 1999. The PAAI Credit Facility bears interest at PAAI's option
at Base Rate (as defined therein) or (i) LIBOR plus 1.75% for Tranche A and (ii)
Libor plus 3.00% prior to September 30, 1998 and LIBOR plus 2.75% thereafter for
Tranche B. PAAI has entered into 10 year interest rate swaps with three of the
lending banks to fix the LIBOR portion of the interest rate for $200 million of
the indebtedness under Tranche B at 5.96% plus the applicable margin.
The PAAI Credit Facility contains covenants, which among other things, require
PAAI to maintain certain financial ratios and minimum net worth. In addition,
the PAAI Credit Facility contains restrictions on additional debt or liens,
hedging contracts, asset sales other than those in the ordinary course of
business, dividends and other distributions, investments, and capital
expenditures above a specified amount.
Plains Marketing & Transportation Inc. Revolving Credit Facility
On July 30, 1998, as a result of the PAAI acquisition and the projected
increased activity, Plains Marketing & Transportation Inc. ("PMTI"), a wholly
owned subsidiary of the Company, increased its letter of credit and inventory
credit facility from $90 million to $175 million (the "PMTI Credit Facility").
The purpose of the PMTI Credit Facility is to provide standby letters of credit
to support the purchase of crude oil for resale and borrowings to finance crude
oil inventory which has been hedged against future price risk. The PMTI Credit
Facility is guaranteed by the Company and by Plains Terminal & Transfer
Corporation and PLX Crude Lines Inc., both wholly-owned subsidiaries of the
Company. The PMTI Credit Facility is secured by all of the assets of PMTI,
primarily accounts receivable and crude oil inventory. Aggregate availability
under the PMTI Credit Facility for direct borrowings and letters of credit is
limited to a borrowing base which is determined monthly based on certain current
assets and current liabilities of PMTI, primarily crude oil inventory and
accounts receivable and accounts payable related to the purchase and sale of
crude oil. At September 30, 1998, the borrowing base was $175.0 million and the
Company had $95.7 million in letters of credit and $11.5 million in borrowings
for inventory outstanding under the PMTI Credit Facility.
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<PAGE>
PMTI has established a $40 million sublimit (the "Sublimit") within the PMTI
Credit Facility for borrowings to finance crude oil purchased in connection with
operations at the Company's crude oil terminal and storage facilities. Under the
terms of the Sublimit, all purchases of crude oil inventory financed are
required to be hedged against future price risk on terms acceptable to the
lenders.
Letters of credit under the PMTI Credit Facility are generally issued for up to
seventy day periods. Borrowings incur interest at the borrower's option of
either (i) the Base Rate, as defined, or (ii) LIBOR plus an applicable margin.
PMTI incurs a commitment fee of 0.25% per annum on the unused portion of the
PMTI Credit Facility. The PMTI Credit Facility has a final maturity date of July
30, 2001.
The PMTI Credit Facility contains covenants, which among other things, require
PMTI to maintain certain financial ratios and minimum levels of working capital
and net worth. In addition, the PMTI Credit Facility contains restrictions on
additional indebtedness, acquisitions, mergers, sale of assets, affiliate
transactions, derivative contracts and capital expenditures.
Plains Resources Inc. Revolving Credit Facility
In May 1998, the Revolving Credit Facility and borrowing base thereunder were
increased to $225 million from $165 million. The Revolving Credit Facility, as
amended, converts to a term loan on July 1, 2000, with a final maturity of July
1, 2005, and bears interest at the option of the Company at LIBOR plus 1.375% or
Base Rate (as defined therein). The Revolving Credit Facility is guaranteed by
all of the Company's principal subsidiaries except PAAI and is secured by the
oil and gas properties of the Company and its subsidiaries and the stock of all
subsidiaries excluding PAAI and the Celeron Companies. At September 30, 1998,
the Company had $154.5 million in borrowings outstanding under the Revolving
Credit Facility.
NOTE 5 -- EARNINGS PER SHARE
The following is a reconciliation of the numerators and the denominators of the
basic and diluted earnings per share ("EPS") computations for income from
continuing operations for the three and nine months ended September 30, 1998 and
1997, respectively, as required by Statement of Financial Accounting Standards
No. 128 ("FAS 128"), Earnings Per Share. Prior period EPS data has been restated
in accordance with the provisions of FAS 128.
<TABLE>
<CAPTION>
FOR THE QUARTER ENDED SEPTEMBER 30,
------------------------------------------------------------------------------
1998 1997
----------------------------------- --------------------------------------
INCOME SHARES PER INCOME SHARES PER
(NUMERA- (DENOMI- SHARE (NUMERA- (DENOMI- SHARE
TOR) NATOR) AMOUNT TOR) NATOR) AMOUNT
--------- --------- ------ -------- --------- ------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
(UNAUDITED)
<S> <C> <C> <C> <C> <C> <C>
Net income $ 3,625 $2,759
Less: preferred stock dividends (1,733) --
-------- ------
Income available to common
stockholders 1,892 16,850 $0.11 2,759 16,627 $0.17
===== =====
Effect of dilutive securities:
Employee stock options -- 1,116 -- 1,189
Warrants -- 549 -- 542
-------- ------- ------ ------
Income available to common
stockholders assuming dilution $ 1,892 18,515 $0.10 $2,759 18,358 $0.15
======== ====== ===== ====== ====== =====
</TABLE>
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<TABLE>
<CAPTION>
FOR THE NINE MONTHS ENDED SEPTEMBER 30,
------------------------------------------------------------------------------
1998 1997
----------------------------------- --------------------------------------
INCOME SHARES PER INCOME SHARES PER
(NUMERA- (DENOMI- SHARE (NUMERA- (DENOMI- SHARE
TOR) NATOR) AMOUNT TOR) NATOR) AMOUNT
--------- --------- ------ -------- --------- ------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
(UNAUDITED)
<S> <C> <C> <C> <C> <C> <C>
Net income $ 6,474 $9,902
Less: preferred stock dividends (2,361) --
-------- ------
Income available to common
stockholders 4,113 16,792 $0.24 9,902 16,572 $0.60
===== =====
Effect of dilutive securities:
Employee stock options -- 1,097 -- 1,027
Warrants -- 551 -- 506
-------- ------- ------ ------
Income available to common
stockholders assuming dilution $ 4,113 18,440 $0.22 $9,902 18,105 $0.55
======== ====== ===== ====== ====== =====
</TABLE>
Certain options and warrants to purchase shares of Common Stock were not
included in the computations of diluted EPS because the exercise prices were
greater than the average market price of the Common Stock during the periods of
the EPS calculations, resulting in antidilution. In addition, the Company's
Series D Preferred Stock and Series E Preferred Stock, are convertible into 5.7
million shares of Common Stock but were not included in the computation of
diluted EPS because the effect was antidilutive.
NOTE 6 -- PLAINS ALL AMERICAN PIPELINE, L.P. OFFERING
On September 23, 1998, Plains All American Pipeline, L.P. (the "Partnership"),
an indirect wholly-owned subsidiary of the Company, filed with the SEC a
registration statement on Form S-1 relating to the sale by the Partnership of
Common Units representing limited partnership interests in the Partnership. The
Partnership was formed to acquire, own and operate the midstream crude oil
business and assets of the Company. Following the proposed offering, the
Partnership will engage in interstate and intrastate crude oil transportation as
well as crude oil terminalling, storage, gathering and marketing, primarily in
California, Texas, Oklahoma, Louisiana and the Gulf of Mexico. Assets of the
Partnership will include the recently acquired All American Pipeline as well as
the Company's storage and terminalling facilities in Cushing, Oklahoma, and
Ingleside, Texas.
Approximately 12,800,000 Common Units (representing an aggregate ownership of
42.6% in the Partnership) will be included in the proposed offering (excluding
approximately 1,900,000 Common Units subject to the Underwriters' over-allotment
option). Upon consummation of the offering, the Company and its affiliates will
continue to own a 57.4% aggregate interest in the Partnership, or 51.0% if the
underwriters' over-allotment is exercised. The Company will use proceeds of the
proposed offering to repay indebtedness and for general corporate purposes.
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<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
THREE MONTH PERIODS ENDED SEPTEMBER 30, 1998 AND 1997
On July 30, 1998, the Company completed the acquisition of the All American
Pipeline, a 1,233-mile crude oil pipeline extending from California to Texas,
and the SJV Gathering System, a 45-mile crude oil gathering system in the San
Joaquin Valley of California (the "All American Pipeline Acquisition"). See
"Capital Resources, Liquidity and Financial Condition". The assets, liabilities
and results of operations of the All American Pipeline Acquisition are included
in the Company's Consolidated Financial Statements effective July 30, 1998. See
Note 2 to the accompanying Consolidated Financial Statements for pro forma
information giving effect to the All American Pipeline Acquisition as if such
transaction occurred on January 1, 1997.
The Company reported continued improvement in the fundamental performance
drivers in both its operating segments during the third quarter of 1998. Oil and
gas production in the upstream segment increased 9% and gross margin from
midstream activities increased 319% over the similar results from last year's
third quarter. Despite improved operating results in both segments, financial
results were adversely affected by a 28% decline in the average benchmark oil
price between the two periods. The NYMEX benchmark oil price averaged $14.18 per
barrel in the third quarter of 1998, compared to the $19.77 per barrel average
for the third quarter of 1997.
For the quarter ended September 30, 1998, the Company reported net income of
$3.6 million, a 31% increase over the $2.8 million recorded in the third quarter
of 1997. After deducting dividends accrued on the Company's Series D & E
Preferred Stock issued subsequent to the third quarter of 1997, the Company
reported net income per common share of $0.11 per share ($0.10 per share
assuming dilution) in the current year quarter as compared to net income per
common share in the prior year period of $0.17 per share ($0.15 per share
assuming dilution). Earnings before interest, taxes, depreciation and
amortization ("EBITDA") for the third quarter of 1998 totaled $24.2 million, a
46% increase over the $16.6 million reported for the prior year period. Cash
flow from operations (net income plus noncash expenses) was $12.7 million for
the third quarter of 1998, up 20% as compared to $10.5 million in the third
quarter of 1997.
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Upstream Results
The following table sets forth certain upstream operating information of the
Company for the periods presented:
<TABLE>
<CAPTION>
THREE MONTHS ENDED
SEPTEMBER 30,
-------------------------------
1998 1997
---------------- ---------------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
(UNAUDITED)
AVERAGE DAILY PRODUCTION VOLUMES:
Barrels of oil equivalent ("BOE")
<S> <C> <C>
California (90% oil) 13.8 11.2
S. Florida (100% oil) 4.8 5.0
Illinois Basin (100% oil) 3.3 3.6
Sold Properties -- 0.2
------- ------
Total (94% oil) 21.9 20.0
======= ======
UNIT ECONOMICS:
Average sales price per BOE $ 12.92 $14.81
Production expenses per BOE 6.42 6.57
-------- ------
Gross margin per BOE 6.50 8.24
Upstream G&A expense per BOE 0.68 0.59
-------- ------
Gross profit per BOE $ 5.82 $ 7.65
======== ======
</TABLE>
Oil and natural gas production for the third quarter of 1998 increased
approximately 9% to an average of 21,900 BOE per day as compared to the third
quarter 1997 average of 20,000 BOE per day. Such increase is primarily
attributable to the Company's ongoing exploitation activities on its three core
properties and to the acquisition of the Arroyo Grande Field in San Luis Obispo
County, California, during the fourth quarter of 1997. During the third quarter
of 1998, the Company shut-in certain of its lower margin wells in California,
Florida and Illinois due to low crude oil prices, resulting in a decrease in
average net daily production of approximately 430 barrels per day. Production in
the prior year period included approximately 200 barrels per day associated with
properties sold subsequent to September 30, 1997. Excluding the impact of the
Arroyo Grande acquisition, the properties sold in 1997 and the shut-in
production, total production was up approximately 6% from the prior year
quarter.
Net daily production in California increased approximately 23% to 13,800 BOE in
the third quarter of 1998 compared to 11,200 BOE in the same quarter of 1997.
Excluding production from the Arroyo Grande Field, total California production
was up approximately 11% over the comparative prior year quarter. Net daily
production in the Illinois Basin averaged approximately 3,300 barrels per day
during the third quarter of 1998, a decrease of approximately 8% as compared to
the 1997 third quarter average of 3,600 barrels per day. Such decrease was
primarily due to the impact of waterflood realignment projects implemented in
the current year, production shut-in due to low oil prices and to normal
decline. Net daily production in South Florida averaged approximately 4,800
barrels per day during the third quarter of 1998, a 4% decrease from the 1997
comparative period due primarily to production shut-in due to low oil prices.
Due to the high volume of production that is generated by a few wells in South
Florida, abrupt or abnormal declines or downtime due to mechanical, marketing,
or other conditions on any of the properties in this area could have a
significant impact on production.
Oil and natural gas revenues were $26.0 million for the third quarter of 1998, a
decrease of 5% from the 1997 third quarter amount due to decreased product
prices which offset increased production volumes. The Company's average product
price, which represents a combination of fixed and floating
12 of 27
<PAGE>
price sales arrangements and incorporates location and quality discounts from
the benchmark NYMEX price was $12.92 per BOE, a decrease of approximately 13% as
compared to 1997's third quarter average realized price of $14.81 per BOE. The
NYMEX benchmark West Texas Intermediate ("WTI") crude oil price averaged $14.18
per barrel during the 1998 third quarter, 28% or $5.59 per barrel below the
$19.77 per barrel average for the third quarter of 1997. The Company maintained
hedges on approximately 60% and 82% of its crude oil production in the third
quarter of 1998 and 1997, respectively, with the current year's hedge price
averaging a NYMEX WTI price of approximately $19.80 per barrel, approximately
$0.61 per barrel higher than last year's average hedge price. Hedging
transactions had the effect of increasing the Company's average price per BOE by
$3.16 in the third quarter of 1998 and decreasing such price by approximately
$0.46 per BOE in the 1997 third quarter.
The Company's realized product price was also negatively affected by higher
location and quality differentials from the NYMEX benchmark price due primarily
to the impact of the lower quality Arroyo Grande crude. The Company's weighted
average differential for all areas was approximately $4.30 per barrel for the
1998 third quarter, compared to approximately $4.00 per barrel during last
year's comparative quarter.
Unit gross margin in the upstream segment was $6.50 per BOE, a 21% decrease as
compared to $8.24 per BOE reported for the third quarter of 1997 on
substantially higher oil prices. Upstream unit gross profit, which deducts
upstream general and administrative ("G&A") expense from gross margin, was $5.82
per BOE, 24% lower than the 1997 amount of $7.65 per BOE. Unit production
expenses decreased by 2% to $6.42 per BOE for the third quarter of 1998, from
$6.57 for the prior year quarter. Total production expenses increased to $12.9
million from $12.1 million for the third quarter of 1997 primarily due to
increased production volumes related to the Company's acquisition and
exploitation activities.
Unit G&A expense in the upstream segment increased 15% to $0.68 per BOE from
$0.59 per BOE primarily due to increased consulting and legal expenses and costs
associated with adapting the Company's computer systems to be "Year 2000"
compliant. Total upstream G&A was $1.4 million for the three months ended
September 30, 1998, compared to $1.1 million for the prior year period.
Depreciation, depletion and amortization ("DD&A") per BOE was $3.00 for the
third quarter of 1998 compared to $2.85 per BOE in the 1997 comparative quarter.
Such increase is primarily attributable to the impact of lower commodity prices
on proved reserve volumes. Total upstream DD&A increased to $6.0 million for the
three months ended September 30, 1998 compared to $5.2 million for the prior
year comparative period due to increased production volumes and the higher per
unit DD&A rate.
13 of 27
<PAGE>
Midstream Results
- -----------------
The following table sets forth certain midstream operating information of the
Company for the periods presented:
<TABLE>
<CAPTION>
THREE MONTHS ENDED
SEPTEMBER 30
-----------------------
1998 1997
----------- ----------
(IN THOUSANDS)
(UNAUDITED)
<S> <C> <C>
Operating Results:
Gross Margin
Pipeline transportation service $ 8,110 $ --
Terminalling and storage and gathering and
marketing 5,804 3,324
------- --------
Total 13,914 3,324
General and administrative expense (1,520) (910)
------- --------
Gross profit $12,394 $ 2,414
======= =======
Average Daily Volumes (barrels):
Pipeline Tariff Activities 117 --
Pipeline Margin Activities 42 --
------- -------
Total 159 --
======= =======
Lease gathering 91 75
Bulk purchases 77 52
Terminal throughput 88 66
</TABLE>
The Company's midstream segment reported gross margin of $13.9 million for the
three months ended September 30, 1998, reflecting a 319% increase over the $3.3
million reported for the same period in 1997. Gross profit (gross margin less
G&A expenses) totaled $12.4 million, a 413% increase over the prior year period.
Midstream results for the three months ended September 30, 1998 include
activities from the All American Pipeline Acquisition since July 30, 1998.
Excluding the two months operating results associated with the All American
Pipeline Acquisition, midstream gross margin and gross profit for the third
quarter of 1998 were $5.8 million and $4.7 million, respectively. Such amounts
exceeded last year's comparative amounts by 75% and 94%, respectively.
Pipeline Operations. Pipeline operations generally consist of (i) transporting
third-party volumes of crude oil for a tariff ("Tariff Activities") and (ii)
merchant activities designed to capture price differentials between the cost to
purchase and transport crude oil to a sales point and the price received for
such crude oil at the sales point ("Margin Activities"). Tariffs on the All
American Pipeline vary by receipt point and delivery point. Tariffs for Outer
Continental Shelf ("OCS") crude oil delivered to California markets currently
average $1.40 per barrel and tariffs for OCS volumes delivered to West Texas
currently average $2.96 per barrel. Tariffs for San Joaquin Valley crude oil
delivered to West Texas currently average $1.25 per barrel. As noted above,
results of operations include approximately two months of operations of the All
American Pipeline System, which was acquired effective July 30, 1998. Gross
margin from pipeline activities totaled $8.1 million for this period. Tariff
revenues were $9.5 million and are primarily attributable to transport volumes
from Exxon's Santa Ynez field (approximately 68,000 barrels per day) and
Chevron's Point Arguello field (approximately 22,900 barrels per day). The
margin between revenue and direct cost of crude purchased was approximately $2.6
million. Operations and maintenance expenses associated with pipeline operations
were $4.0 million.
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<PAGE>
The following table sets forth All American Pipeline average deliveries per day
within and outside California since July 30, 1998.
DELIVERIES:
Average daily volumes (thousand barrels):
Within California 113
Outside California 46
---
159
===
Terminalling and Storage Activities and Gathering and Marketing Activities. The
Company reported gross margin of $5.8 million from its terminalling and storage
activities and gathering and marketing activities for the three months ended
September 30, 1998, reflecting a 75% increase over the $3.3 million reported for
the same period in 1997. Net of interest expense associated with contango
inventory transactions, gross margin for the three months ended September 30,
1998 was $5.5 million, approximately 96% above the 1997 amount of $2.8 million,
also excluding contango interest. The increase in gross margin was primarily
attributable to an increase in the volumes gathered and marketed, principally in
West Texas, Louisiana and the Gulf of Mexico of approximately 21% to 91,000
barrels per day for the three months ended September 30, 1998, from 75,000
barrels per day during the same period in 1997. The balance of the increase in
gross margin was primarily a result of an increase in bulk purchases. Average
terminal throughput increased by 22,000 barrels per day to 88,000 barrels during
the three months ended September 30, 1998, from 66,000 barrels per day in the
same period of 1997.
Expenses. Midstream G&A expenses increased approximately $0.6 million to $1.5
million for the three months ended September 30, 1998, compared to $0.9 million
for the same period in 1997. Such increase was primarily related to the All
American Pipeline Acquisition and additional personnel hired to further expand
marketing activities. Midstream depreciation and amortization expense increased
to $2.0 million for the three months ended September 30, 1998 from $0.3 million
for the comparable 1997 period due primarily to the All American Pipeline
Acquisition.
General
Interest expense for the third quarter of 1998 increased to $11.5 million from
$6.0 million for the comparative prior year period primarily due the All
American Pipeline Acquisition and to higher outstanding debt levels related to
the Company's upstream acquisition, exploitation and development activities. The
current year quarter includes approximately $4.5 million of interest related to
the All American Pipeline Acquisition. Capitalized interest was $0.9 million and
$0.8 million for the three months ended September 30, 1998 and 1997,
respectively.
The Company's total tax provision for the quarter ended September 30, 1998, was
approximately $0.7 million, as compared to the third quarter 1997 tax provision
of approximately $1.8 million. During the 1998 third quarter, the Company
reduced the valuation allowance reserved against its deferred tax asset by
approximately $2.9 million due to the utilization of certain net operating loss
carryforwards which had previously been reserved. The reduction in the valuation
allowance results in an approximate $1.0 million tax benefit which is included
in the Company's third quarter 1998 income tax provision, resulting in an
effective tax rate of approximately 17% for such quarter. The Company's
effective tax rate for the comparative 1997 period was 40%. In both periods,
substantially all of the Company's income tax provision was deferred.
15 of 27
<PAGE>
NINE MONTH PERIODS ENDED SEPTEMBER 30, 1998 AND 1997
The Company reported continued improvement in the fundamental performance
drivers in both its operating segments during the first nine months of 1998. Oil
and gas production in the upstream segment increased 14% and gross margin from
midstream activities increased 161% over the similar results for the comparative
1997 period. Despite improved operating results in both segments, financial
results were adversely affected by a 28% decline in the average benchmark oil
price between the two periods. The NYMEX benchmark oil price averaged $14.95 per
barrel in the first nine months of 1998, compared to the $20.85 per barrel
average for the 1997 period.
For the nine months ended September 30, 1998, the Company reported net income of
$6.5 million or $0.24 per share ($0.22 per share assuming dilution). This
compares with net income in the prior year period of $9.9 million or $0.60 per
share ($0.55 per share assuming dilution) on substantially higher oil prices.
For the first nine months of 1998, cash flow from operations decreased 8% to
$30.9 million and EBITDA increased 11% to $55.3 million. Net cash provided by
operating activities, as reported in the consolidated statements of cash flows,
increased to $35.5 million for the nine months ended September 30, 1998, as
compared to $2.9 million of net cash used by operating activities for the 1997
comparative period. Such increase is primarily due to an increase in inventory
levels in the prior year period and the timing of cash receipts and payments
between the two periods. Results for the nine months ended September 30, 1998,
include activities from the All American Pipeline Acquisition since July 30,
1998.
Upstream Results
The following table sets forth certain upstream operating information of the
Company for the periods presented:
NINE MONTHS ENDED
SEPTEMBER 30,
-------------------------------
1998 1997
------------ ------------
(IN THOUSANDS, EXCEPT PER
UNIT DATA)
(UNAUDITED)
AVERAGE DAILY PRODUCTION VOLUMES:
Barrels of oil equivalent
California (90% oil) 13.7 10.7
S. Florida (100% oil) 5.0 5.2
Illinois Basin (100% oil) 3.6 3.5
Sold Properties -- 0.2
------ -----
Total (94% oil) 22.3 19.6
====== =====
UNIT ECONOMICS:
Average sales price per BOE $12.77 $14.91
Production expenses per BOE 6.35 6.17
------ ------
Gross margin per BOE 6.42 8.74
Upstream G&A expense per BOE 0.68 0.67
------ ------
Gross profit per BOE $ 5.74 $ 8.07
====== ======
Oil and natural gas production for the first nine months of 1998 averaged
approximately 22,300 BOE per day, a 14% increase over the 19,600 BOE per day
averaged during the same period of 1997. Total production for the first nine
months of 1998 increased to 6.1 million BOE versus the 5.4 million BOE produced
in the 1997 comparative period. The increase in production volumes is primarily
attributable to the Company's ongoing exploitation activities on its three core
properties and to the acquisition of two California producing properties during
1997. The Montebello and the Arroyo Grande fields were acquired during the first
quarter and fourth quarter of 1997, respectively.
16 of 27
<PAGE>
Net daily production in California increased approximately 28% to 13,700 BOE in
the first nine months of 1998, compared to 10,700 BOE in the 1997 comparative
period. Excluding production from the Arroyo Grande field, total California
production was up 15% over the comparative prior year period. Net daily
production in the Illinois Basin averaged approximately 3,600 barrels per day
during the first nine months of 1998, an increase of approximately 3% over the
1997 period. Net daily production from the Company's South Florida properties
decreased approximately 4% to average 5,000 barrels of oil per day in the first
nine months of 1998 as compared to 5,200 barrels per day in last year's
comparative period. Due to the high volume of production that is generated by a
few wells in South Florida, abrupt or abnormal declines or downtime due to
mechanical, marketing, or other conditions on any of the properties in this area
could have a significant impact on production.
Oil and natural gas revenues were $77.7 million for the first nine months of
1998, a decrease of 3% from the 1997 comparative period due to decreased product
prices which offset increased production volumes. The Company's average product
price, which represents a combination of fixed and floating price sales
arrangements and incorporates location and quality discounts from the benchmark
NYMEX price was $12.77 per BOE, a decrease of approximately 14% as compared to
1997's nine month average of $14.91 per BOE. Approximately 59% and 82% of the
Company's oil production was hedged during the first nine months of 1998 and
1997, respectively, with the current year's hedge price averaging a NYMEX WTI
price of approximately $19.80 per barrel, approximately $0.46 per barrel higher
than last year's average hedge price. Hedging transactions had the effect of
increasing the average price per BOE by $2.67 in the first nine months of 1998
and decreasing such price by approximately $1.49 per BOE in the 1997 period.
The Company's realized product price was also negatively affected by higher
location and quality differentials from the NYMEX benchmark price due to the
weakening of price spreads between heavy crude oil and light crude oil and the
impact of the lower quality Arroyo Grande crude. The Company's weighted average
differential for all areas was approximately $4.77 per barrel for the first nine
months of 1998, compared to approximately $4.08 per barrel during last year's
comparative period.
Unit gross margin in the upstream segment was $6.42 per BOE, a 27% decrease as
compared to $8.74 per BOE reported for the first nine months of 1997 on
substantially higher oil prices. Upstream unit gross profit, which deducts
upstream G&A expenses from gross margin, was $5.74 per BOE, 29% lower than the
1997 amount of $8.07 per BOE. Unit production expenses increased $0.18 per BOE
from $6.17 per BOE last year, largely as a result of the addition late in 1997
of properties with higher operating costs. Total production expenses increased
to $38.6 million from $33.1 million for the first nine months of 1997 primarily
due to increased production volumes related to the Company's acquisition and
exploitation activities.
Unit G&A expense in the upstream segment was generally flat with the prior year.
Unit G&A expense was $0.68 per BOE for the nine months ended September 30, 1998,
compared to $0.67 per BOE in the prior year period. Total upstream G&A was $4.1
million for the first nine months of 1998 compared to $3.6 million for the prior
year period. DD&A per BOE was $3.00 for the first nine months of 1998 compared
to $2.82 per BOE in the 1997 comparative period. Such increase is primarily
attributable to the impact of lower commodity prices on proved reserve volumes.
Total upstream DD&A expense increased to $18.3 million for the nine months ended
September 30, 1998, from $15.1 million for the 1997 period due to increased
production volumes and the higher upstream DD&A rate.
17 of 27
<PAGE>
Midstream Results
- -----------------
The following table sets forth certain midstream operating information of the
Company for the periods presented:
NINE MONTHS ENDED
SEPTEMBER 30
-----------------------
1998 1997
-------- ---------
(IN THOUSANDS)
(UNAUDITED)
OPERATING RESULTS:
Gross Margin
Pipeline transportation service $ 8,110 $ --
Terminalling and storage and gathering
and marketing 15,004 8,854
------- -------
Total 23,114 8,854
General and administrative expense (3,561) (2,616)
------- -------
Gross profit $19,553 $ 6,238
======= ========
AVERAGE DAILY VOLUMES (BARRELS):
Pipeline Tariff Activities 117 --
Pipeline Margin Activities 42 --
------- -------
Total 159 --
======= ========
Lease gathering 85 70
Bulk purchases 94 46
Terminal throughput 79 78
The Company's midstream segment reported gross margin of $23.1 million for the
nine months ended September 30, 1998, reflecting a 161% increase over the $8.9
million reported for the same period in 1997. Gross profit (gross margin less
G&A expenses) totaled $19.6 million, a 213% increase over the prior year period.
Midstream results for the nine months ended September 30, 1998 include
activities from the All American Pipeline Acquisition since July 30, 1998.
Excluding the two months operating results associated with the All American
Pipeline Acquisition, midstream gross margin and gross profit for the first nine
months of 1998 were $15.0 million and $11.9 million, respectively. Such amounts
exceeded last year's comparative amounts by 69% and 90%, respectively.
Pipeline Operations. Pipeline operations generally consist of (i) transporting
third-party volumes of crude oil for a tariff and (ii) merchant activities
designed to capture price differentials between the cost to purchase and
transport crude oil to a sales point and the price received for such crude oil
at the sales point. Tariffs on the All American Pipeline vary by receipt point
and delivery point. Tariffs for OCS crude oil delivered to California markets
currently average $1.40 per barrel and tariffs for OCS volumes delivered to West
Texas currently average $2.96 per barrel. Tariffs for San Joaquin Valley crude
oil delivered to West Texas currently average $1.25 per barrel. As noted above,
the results of operations include approximately two months of operations of the
All American Pipeline System, which was acquired effective July 30, 1998. Gross
margin from pipeline operations totaled $8.1 million for this period. Tariff
revenues were $9.5 million and are primarily attributable to transport volumes
from Exxon's Santa Ynez field (approximately 68,000 barrels per day) and
Chevron's Point Arguello field (approximately 22,900 barrels per day). The
margin between revenue and direct cost of crude purchased was approximately $2.6
million. Operations and maintenance expenses associated with pipeline operations
were $4.0 million.
18 of 27
<PAGE>
The following table sets forth All American Pipeline average deliveries per day
within and outside California since July 30, 1998.
DELIVERIES:
Average daily volumes (thousand barrels):
Within California 113
Outside California 46
---
159
===
Terminalling and Storage Activities and Gathering and Marketing Activities. The
Company reported gross margin of $15.0 million from its terminalling and storage
activities and gathering and marketing activities for the nine months ended
September 30, 1998, reflecting a 69% increase over the $8.9 million reported for
the same period in 1997. Net of interest expense associated with contango
inventory transactions, gross margin for the nine months ended September 30,
1998 was $14.4 million, approximately 74% above the 1997 amount of $8.3 million,
also excluding contango interest. The increase in gross margin was primarily
attributable to an increase in volumes gathered and marketed, principally in
West Texas, Louisiana and the Gulf of Mexico of approximately 21% to 85,000
barrels per day for the nine months ended September 30, 1998, from 70,000
barrels per day during the same period in 1997. The balance of the increase in
gross margin was primarily a result of an increase in bulk purchases and profits
created by arbitrage opportunities associated with a contango market. Average
terminal throughput increased slightly to 79,000 barrels per day for the nine
months ended September 30, 1998, as compared to the same period in 1997.
Expenses. Midstream G&A expenses increased approximately $1.0 million to $3.6
million for the nine months ended September 30, 1998, compared to $2.6 million
for the same period in 1997. Such increase was primarily related to the All
American Pipeline Acquisition and additional personnel hired to further expand
marketing activities. Midstream depreciation and amortization expense increased
to $2.6 million for the nine months ended September 30, 1998 from $0.9 million
for the comparable 1997 period due primarily to the All American Pipeline
Acquisition.
General
- -------
Interest expense for the first nine months of 1998 increased to $24.4 million
from $15.9 million for the comparative prior year period primarily due to the
All American Pipeline Acquisition and to higher outstanding debt levels related
to the Company's upstream acquisition, exploitation and development activities.
The current year period includes approximately $5.0 million of interest related
to the All American Pipeline Acquisition. Capitalized interest was $2.7 million
and $2.3 million for the nine months ended September 30, 1998 and 1997,
respectively.
The Company's total tax provision for the nine months ended September 30, 1998,
was approximately $2.5 million, as compared to $6.6 million for the 1997
comparative period. During the 1998 third quarter, the Company reduced the
valuation allowance reserved against its deferred tax asset by approximately
$2.9 million due to the utilization of certain net operating loss carryforwards
which had previously been reserved. The reduction in the valuation allowance
results in an approximate $1.0 million tax benefit which is included in the
Company's income tax provision for the nine months ended September 30, 1998,
resulting in an effective tax rate of approximately 28% for such period. The
Company's effective tax rate for the comparative 1997 period was 40%. In both
periods, substantially all of the Company's income tax provision was deferred.
In July 1997, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards No. 131 ("FAS 131"), Disclosures About
Segments of an Enterprise and Related Information, effective for fiscal years
beginning after December 15, 1997. FAS 131 introduces a new
19 of 27
<PAGE>
model for segment reporting and requires disclosures for each segment that are
similar to those required under current standards with the addition of quarterly
disclosure requirements and a finer partitioning of geographic disclosures.
Reportable segments are based on products and services, geography, legal
structure, management structure or any manner in which management disaggregates
a company. This statement replaces the notion of industry and geographic
segments in current FASB standards. Management is currently evaluating the
impact of this statement on the Company's disclosures.
In June 1998, the FASB issued Statement of Financial Accounting Standards No.
133, Accounting for Derivative Instruments and Hedging Activities ("FAS 133").
FAS 133 is effective for all fiscal years beginning after June 15, 1999 (January
1, 2000 for the Company). FAS 133 requires that all derivative instruments be
recorded on the balance sheet at their fair value. Changes in the fair value of
derivatives are recorded each period in current earnings or other comprehensive
income, depending on whether a derivative is designated as part of a hedge
transaction and, if it is, the type of hedge transaction. For fair-value hedge
transactions in which the Company is hedging changes in an asset's, liability's,
or firm commitment's fair value, changes in the fair value of the derivative
instrument will generally be offset in the income statement by changes in the
hedged item's fair value. For cash-flow hedge transactions, in which the Company
is hedging the variability of cash flows related to a variable-rate asset,
liability, or a forecasted transaction, changes in the fair value of the
derivative instrument will be reported in other comprehensive income. The gains
and losses on the derivative instrument that are reported in other comprehensive
income will be reclassified as earnings in the periods in which earnings are
impacted by the variability of the cash flows of the hedged item. The Company
has not yet determined the impact that the adoption of FAS 133 will have on its
earnings or financial position.
CAPITAL RESOURCES, LIQUIDITY AND FINANCIAL CONDITION
On September 23, 1998, Plains All American Pipeline, L.P. (the "Partnership"),
an indirect wholly-owned subsidiary of the Company, filed with the SEC a
registration statement on Form S-1 relating to the sale by the Partnership of
Common Units representing limited partnership interests in the Partnership. The
Partnership was formed to acquire, own and operate the midstream crude oil
business and assets of the Company. Following the proposed offering, the
Partnership will engage in interstate and intrastate crude oil transportation as
well as crude oil terminalling, storage, gathering and marketing, primarily in
California, Texas, Oklahoma, Louisiana and the Gulf of Mexico. Assets of the
Partnership will include the recently acquired All American Pipeline as well as
the Company's storage and terminalling facilities in Cushing, Oklahoma, and
Ingleside, Texas.
Approximately 12,800,000 Common Units (representing an aggregate ownership of
42.6% in the Partnership) will be included in the proposed offering (excluding
approximately 1,900,000 Common Units subject to the Underwriters' over-allotment
option). Upon consummation of the offering, the Company and its affiliates will
continue to own a 57.4% aggregate interest in the Partnership, or 51.0% if the
underwriters' over-allotment is exercised. The Company will use proceeds of the
proposed offering to repay indebtedness and for general corporate purposes.
On July 30, 1998, Plains All American Inc. ("PAAI"), a wholly owned unrestricted
subsidiary of the Company, as defined in the indentures for the Company's $200
million 10.25% Senior Subordinated Notes (the "Indentures"), acquired all of the
outstanding capital stock of the All American Pipeline Company, Celeron
Gathering Corporation and Celeron Trading & Transportation Company (collectively
the "Celeron Companies") from Wingfoot Ventures Seven, Inc., a wholly-owned
subsidiary of The Goodyear Tire & Rubber Company ("Goodyear") for approximately
$400 million, including transaction costs. The principal assets of the entities
acquired include the All American Pipeline System, a 1,233-mile crude oil
pipeline extending from California to Texas, and a 45-mile
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<PAGE>
crude oil gathering system in the San Joaquin Valley of California, as well as
other assets related to such operations.
Financing for the acquisition was provided through (i) PAAI's $325 million,
limited recourse bank facility with ING (U.S.) Capital Corporation, BankBoston,
N.A. and other lenders (the "PAAI Credit Facility") and (ii) an approximate $114
million capital contribution to PAAI by the Company. Approximately $29 million
of such capital contribution was funded by cash flow and the Company's revolving
credit facility (the "Revolving Credit Facility") and the remaining $85 million
was provided by a privately placed issuance of the Company's Series E Cumulative
Convertible Preferred Stock (the "Series E Preferred Stock").
On July 29, 1998, the Company sold in a private placement 170,000 shares of its
Series E Preferred Stock for $85 million. Each share of the Series E Preferred
Stock has a stated value of $500 per share and bears a dividend of 9.5% per
annum. Dividends are payable semi-annually in either cash or additional shares
of Series E Preferred Stock at the Company's option and are cumulative from the
date of issue. Each share of Series E Preferred Stock is convertible into 27.78
shares of the Company's common stock ("Common Stock") (an initial effective
conversion price of $18.00 per share) and in certain circumstances may be
converted at the Company's option into Common Stock if the average trading price
for any thirty-day trading period is equal to or greater than $21.60 per share.
The Series E Preferred Stock is redeemable at the option of the Company after
March 31, 1999, at 110% of stated value and at declining amounts thereafter. If
not previously redeemed or converted, the Series E Preferred Stock is required
to be redeemed in 2012.
Proceeds from the Series E Preferred Stock were used to fund a portion of the
Company's capital contribution to PAAI to acquire all of the outstanding capital
stock of the Celeron Companies.
On July 30, 1998, PAAI borrowed $300 million under the PAAI Credit Facility.
Such proceeds were used to acquire all of the outstanding capital stock of the
Celeron Companies from Goodyear and to provide initial working capital. At
September 30, 1998, the Company had $285 million outstanding under the PAAI
Credit Facility.
The PAAI Credit Facility is guaranteed by the Celeron Companies and is secured
by the assets of PAAI and the Celeron Companies, including all pipelines
(including associated linefill), gathering lines, accounts receivable, inventory
and the capital stock of the Celeron Companies. The PAAI Credit Facility
consists of (i) a $100 million reducing, revolving line of credit with a $30
million sub-limit for letters of credit ("Tranche A") and (ii) a $225 million
non-amortizing term loan ("Tranche B"). PAAI incurs a commitment fee of 0.5% per
annum on the unused portion of Tranche A. The commitment for Tranche A reduces
in twenty-four equal quarterly amounts commencing September 30, 1998, with final
maturity on June 30, 2004. Tranche B of the PAAI Credit Facility is repayable at
maturity on June 30, 2005. Prepayment of principal on Tranche B is subject to a
penalty of 1% on amounts prepaid prior to December 31, 1998, and 0.5% thereafter
through June 30, 1999. The PAAI Credit Facility bears interest at PAAI's option
at Base Rate (as defined therein) or (i) LIBOR plus 1.75% for Tranche A and (ii)
Libor plus 3.00% prior to September 30, 1998, and LIBOR plus 2.75% thereafter
for Tranche B. PAAI has entered into 10 year interest rate swaps with three of
the lending banks to fix the LIBOR portion of the interest rate for $200 million
of the indebtedness under Tranche B at 5.96% plus the applicable margin.
The PAAI Credit Facility contains covenants, which among other things, requires
PAAI to maintain certain financial ratios and minimum net worth. In addition,
the PAAI Credit Facility contains restrictions on additional debt or liens,
hedging contracts, asset sales other than those in the ordinary course of
business, dividends and other distributions, investments and capital
expenditures above a specified amount.
21 of 27
<PAGE>
On July 30, 1998, as a result of the PAAI acquisition and the projected
increased activity, Plains Marketing & Transportation Inc. ("PMTI"), a wholly
owned subsidiary of the Company, increased its letter of credit and inventory
credit facility from $90 million to $175 million (the "PMTI Credit Facility").
The purpose of the PMTI Credit Facility is to provide standby letters of credit
to support the purchase of crude oil for resale and borrowings to finance crude
oil inventory which has been hedged against future price risk. The PMTI Credit
Facility is guaranteed by the Company and by Plains Terminal & Transfer
Corporation and PLX Crude Lines Inc., both wholly-owned subsidiaries of the
Company. The PMTI Credit Facility is secured by all of the assets of PMTI,
primarily accounts receivable and crude oil inventory. Aggregate availability
under the PMTI Credit Facility for direct borrowings and letters of credit is
limited to a borrowing base which is determined monthly based on certain current
assets and current liabilities of PMTI, primarily crude oil inventory and
accounts receivable and accounts payable related to the purchase and sale of
crude oil. At September 30, 1998, the borrowing base was $175.0 million and the
Company had $95.7 million in letters of credit and $11.5 million in borrowings
for inventory outstanding under the PMTI Credit Facility.
PMTI has established a $40 million sublimit (the "Sublimit") within the PMTI
Credit Facility for borrowings to finance crude oil purchased in connection with
operations at the Company's crude oil terminal and storage facilities. Under the
terms of the Sublimit, all purchases of crude oil inventory financed are
required to be hedged against future price risk on terms acceptable to the
lenders.
Letters of credit under the PMTI Credit Facility are generally issued for up to
seventy day periods. Borrowings incur interest at the borrower's option of
either (i) the Base Rate, as defined, or (ii) LIBOR plus an applicable margin.
PMTI incurs a commitment fee of 0.25% per annum on the unused portion of the
PMTI Credit Facility. The PMTI Credit Facility has a final maturity date of July
30, 2001.
The PMTI Credit Facility contains covenants, which among other things, require
PMTI to maintain certain financial ratios and minimum levels of working capital
and net worth. In addition, the PMTI Credit Facility contains restrictions on
additional indebtedness, acquisitions, mergers, sale of assets, affiliate
transactions, derivative contracts, and capital expenditures.
In May 1998, the Revolving Credit Facility and borrowing base thereunder were
increased to $225 million from $165 million. The Revolving Credit Facility, as
amended, converts to a term loan on July 1, 2000, with a final maturity of July
1, 2005, and bears interest at the option of the Company at LIBOR plus 1.375% or
Base Rate (as defined therein). The Revolving Credit Facility is guaranteed by
all of the Company's principal subsidiaries except PAAI and is secured by the
oil and gas properties of the Company and its subsidiaries and the stock of all
subsidiaries excluding PAAI and the Celeron Companies. At September 30, 1998,
the Company had $154.5 million in borrowings outstanding under the Revolving
Credit Facility.
At September 30, 1998, the Company had a working capital deficit of
approximately $5.9 million compared to a working capital deficit of $6.0 million
at December 31, 1997. The Company has historically operated with a working
capital deficit due primarily to ongoing capital expenditures that have been
financed through cash flow, the Revolving Credit Facility, and the sale of
subordinated notes, common stock and preferred stock.
22 of 27
<PAGE>
INVESTING AND FINANCING ACTIVITIES
Net cash flows used in investing activities were $462.3 million and $78.7
million for the nine months ended September 30, 1998 and 1997, respectively.
Approximately $393.9 million related to the All American Pipeline Acquisition is
included in investing activities for 1998. Investing activities include payments
for acquisition, exploration and development costs of $62.7 million and $74.8
million for the nine months ended September 30, 1998 and 1997, respectively.
Included in the 1997 amount is approximately $25 million related to the
acquisition of the Montebello field.
Net cash provided by financing activities amounted to $431.0 million and $82.1
million for the nine months ended September 30, 1998 and 1997, respectively.
Financing activities for 1998 include the following related to the All American
Pipeline Acquisition: (i) approximately $300 million in borrowings and $15
million of repayments under the PAAI Credit Facility, (ii) proceeds of $85
million from the issuance of the Series E Preferred Stock and (iii)
approximately $16 million in borrowings under the Revolving Credit Facility to
fund the Company's capital contribution to PAAI. In 1997, approximately $25
million borrowed under the Revolving Credit Facility to fund the acquisition of
the Montebello field is included in proceeds from long-term debt. Included in
both years are net proceeds from borrowings under the Revolving Credit Facility
as a result of acquisition, exploration, exploitation and development
activities. Financing activities during the first nine months of 1998 include
approximately $28.8 million in short-term borrowings and approximately $35.3
million of repayments related to contango crude oil inventory transactions at
the Company's Cushing terminal. In 1997, proceeds of $25 million related to
contango crude oil inventory transactions are included in financing activities.
CHANGING OIL AND NATURAL GAS PRICES
The Company is affected by changes in crude oil prices, which have historically
been volatile. Although the Company has routinely hedged a substantial portion
of its crude oil production and intends to continue this practice, prolonged low
crude oil prices or future crude oil price declines would have a negative impact
on the Company's overall results, and therefore its liquidity. Furthermore, low
crude oil prices could affect the Company's ability to raise capital on terms
favorable to the Company. In order to manage its exposure to commodity price
risk, the Company has routinely hedged a portion of its crude oil production.
For the remainder of 1998, the Company has entered into various hedging
arrangements on approximately 12,250 barrels of oil per day, or approximately
60% of 1998 third quarter crude oil production at a NYMEX WTI price of
approximately $19.80 per barrel. In addition, the Company also has fixed price
arrangements on 9,000 barrels per day in 1999 at a NYMEX WTI price of $18.25 per
barrel, or approximately 44% of third quarter 1998 crude oil production levels.
The foregoing NYMEX WTI prices are before quality and location differentials.
Management intends to continue to maintain hedging arrangements for a
significant portion of its production. Such contracts may expose the Company to
the risk of financial loss in certain circumstances.
Additionally, decreases in the prices of oil and natural gas have had, and could
have in the future, an adverse effect on the carrying value of the Company's
proved reserves and the Company's revenues, profitability and cash flow. Almost
all of the Company's reserve base (approximately 94% of year-end 1997 reserve
volumes) is comprised of long-life oil properties that are sensitive to crude
oil price volatility. The crude oil price received by the Company at December
31, 1997, upon which proved reserve volumes, the estimated present value
(discounted at 10%) of future net revenue from the Company's proved oil and
natural gas reserves (the "Present Value of Proved Reserves") and the Present
Value of Proved Reserves reduced by future discounted income taxes (the
"Standardized Measure") as of such date were based, was $18.34 per barrel.
During 1998, the benchmark NYMEX crude oil price has fluctuated significantly,
closing as high as $17.82 per barrel and as low as $11.56 per barrel. Under full
cost accounting rules as prescribed by the SEC, unamortized costs of proved oil
23 of 27
<PAGE>
and natural gas properties are subject to a ceiling, which limits such costs to
the Standardized Measure. Subject to ongoing exploitation and production
activities which may affect the estimated volumes and values of the Company's
oil and gas properties, the Company estimates that the Standardized Measure of
the Company's proved reserves will approximate the book carrying cost of such
properties at a NYMEX benchmark crude oil price between $14.00 and $15.00 per
barrel and in the future the Company could be required to record a noncash
writedown of such capitalized costs. This estimated price range is based on
average historical differentials between the NYMEX WTI benchmark oil price and
the Company's average wellhead realizations. Such wellhead realizations are
affected by quality and location factors. Variations from these average
differentials at any given point in time will affect the Company's estimates of
proved reserve volumes and values.
YEAR 2000
Year 2000 Issue. Many software applications, hardware and equipment and embedded
chip systems identify dates using only the last two digits of the year. These
products may be unable to distinguish between dates in the Year 2000 and dates
in the year 1900. That inability (referred to as the "Year 2000" issue), if not
addressed, could cause applications, equipment or systems to fail or provide
incorrect information after December 31, 1999, or when using dates after
December 31, 1999. This in turn could have an adverse effect on the Company, due
to the Company's direct dependence on its own applications, equipment and
systems and indirect dependence on those of other entities with which the
Company must interact.
Compliance Program. In order to address the Year 2000 issues, the Company has
implemented a Year 2000 project for all of its business units. A project team
has been established to coordinate the five phases of this Year 2000 project to
assure that key automated systems and related processes will remain functional
through Year 2000. Those phases include: (i) awareness, (ii) assessment,
(iii) remediation, (iv) testing and (v) implementation of the necessary
modifications. The key automated systems consist of (a) financial systems
applications, (b) hardware and equipment, (c) embedded chip systems and
(d) third-party developed software. The evaluation of the Year 2000 issue
includes the evaluation of the Year 2000 exposure of third parties material to
the operations of the Company or any of its business units. The Company retained
a Year 2000 consulting firm to review the operations of all of its business
units and to assess the impact of the Year 2000 issue on such operations. Such
review has been completed and the consultant's recommendations are being
utilized in the Year 2000 project.
The Company's State of Readiness. The awareness phase of the Year 2000 project
has begun with a corporate-wide awareness program which will continue to be
updated throughout the life of the project. The portion of the assessment phase
related to financial systems applications has been substantially completed and
the necessary modifications and conversions are underway. The portion of the
assessment phase which will determine the nature and impact of the Year 2000
issue for hardware and equipment, embedded chip systems, and third-party
developed software is continuing. The assessment phase of the project involves,
among other things, efforts to obtain representations and assurances from third
parties, including third party vendors, that their hardware and equipment,
embedded chip systems, and software being used by or impacting the Company or
any of its business units are or will be modified to be Year 2000 compliant. To
date, the responses from such third parties are inconclusive. As a result,
management cannot predict the potential consequences if these or other third
parties are not Year 2000 compliant. The exposure associated with the Company's
interaction with third parties is currently being evaluated.
Management expects that the remediation, testing and implementation phases will
be substantially completed by mid-1999.
Costs to Address Year 2000 Compliance Issues. While the total cost to the
Company of the Year 2000 project is still being evaluated, management currently
estimates that the costs to be incurred by the Company in the remainder of 1998,
1999 and 2000 associated with assessing, testing, modifying or replacing
financial system applications, hardware and equipment, embedded chip systems,
and third party developed software is between $0.7 million and $0.8 million. The
Company expects to fund these expenditures with cash from operations or
borrowings. To date, the Company has expended approximately $160,000.
24 of 27
<PAGE>
Risk of Non-Compliance and Contingency Plans. The major applications which pose
the greatest Year 2000 risks for the Company if implementation of the Year 2000
compliance program is not successful are the Company's financial systems
applications and the Company's supervisory control and data acquisition
("SCADA") computer system and embedded chip systems in field equipment. The
potential problems if the Year 2000 compliance program is not successful are
disruptions of the Company's revenue gathering from and distribution to its
customers and vendors and the inability to perform its other financial and
accounting functions. Failures of embedded chip systems in field equipment of
the Company or its customers could disrupt the Company's upstream exploitation,
development, production and exploration activities and its midstream crude oil
transportation, terminalling and storage activities and gathering and marketing
activities.
The goal of the Year 2000 project is to ensure that all of the critical systems
and processes which are under the direct control of the Company and its business
units remain functional. However, because certain systems and processes may be
interrelated with systems outside of the control of the Company and its business
units, there can be no assurance that all implementations will be successful.
Accordingly, as part of the Year 2000 project, contingency and business plans
will be developed to respond to any failures as they may occur. Such contingency
and business plans are scheduled to be completed by mid-year 1999. Management
does not expect the costs to the Company for the Year 2000 project to have a
material adverse effect on the Company's financial position, results of
operations or cash flows. Based on information available at this time, however,
the Company cannot conclude that any failure of the Company or third parties to
achieve Year 2000 compliance will not aversely affect the Company.
FORWARD-LOOKING STATEMENTS AND ASSOCIATED RISKS
All statements, other than statements of historical facts, included in this
report which address activities, events or developments that the Company expects
or anticipates will or may occur in the future are forward-looking statements.
Such forward-looking statements are subject to risks and uncertainties
including, among other things, market conditions, drilling and operating
hazards, uncertainties inherent in estimating oil and gas reserves and other
factors discussed in the Company's Annual Report on Form 10-K for the year ended
December 31, 1997.
25 of 27
<PAGE>
PART II. OTHER INFORMATION
Item 1 - Legal Proceedings
None
Item 2 - Material Modification of Rights of Registrant's Securities
None
Item 3 - Defaults on 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
10(z) -- First Amendment to Plains Resources Inc. 1996 Stock Incentive
Plan dated May 21, 1998.
10(aa) -- Third Amendment to Plains Resources Inc. 1992 Stock Incentive
Plan dated May 21, 1998.
27. -- Financial Data Schedule
B. Report on Form 8-K
An amendment to Form 8-K on Form 8-KA with respect to the Company's
purchase by Plains All American Inc. (a wholly owned subsidiary of the
Company) of all the outstanding capital stock of the All American
Pipeline Company, Celeron Gathering Corporation and Celeron Trading &
Transportation Company from a subsidiary of the Goodyear Tire & Rubber
Company was filed on September 30, 1998. Such form 8-KA is hereby
incorporated by reference.
26 of 27
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned and thereunto duly authorized.
PLAINS RESOURCES INC.
Date: November 12, 1998 By: /s/ Cynthia A. Feeback
-------------------------------
Cynthia A. Feeback, Controller,
Assistant Treasurer and
Principal Accounting Officer
(Principal Accounting Officer)
27 of 27
<PAGE>
EXHIBIT 10.Z
FIRST AMENDMENT TO
PLAINS RESOURCES INC.
1996 STOCK INCENTIVE PLAN
Plains Resources Inc., having heretofore adopted the Plains Resources Inc.
1996 Stock Incentive Plan (the "Plan") and having reserved the right under
Section 9 thereof to amend the Plan, does hereby amend the Plan, effective as of
May 21, 1998, as follows:
Section 8.1 of Plains Resources Inc. 1996 Stock Incentive Plan shall be
amended to read as follows:
8.1 Award On the date of the Company's annual stockholders' meeting
at which the Non-employee Director is elected or re-elected to serve on the
Board, each Non-employee Director shall be granted a Non-qualified Stock
Option to purchase 15,000 Shares, provided that the Plan is in effect on
that day.
Adopted by the Board of Directors of Plains Resources Inc. on May 21, 1998.
<PAGE>
EXHIBIT 10.AA
THIRD AMENDMENT TO
PLAINS RESOURCES INC.
1992 STOCK INCENTIVE PLAN
Plains Resources Inc., having heretofore adopted the Plains Resources Inc.
1992 Stock Incentive Plan (the "Plan"), as amended by that certain First
Amendment to the Plan dated February 6, 1997 and the Second Amendment to the
Plan dated May 22, 1997, and having reserved the right under Section 9 thereof
to amend the Plan, does hereby amend the Plan, effective as of May 21, 1998, as
follows:
Article 8 of the Plan is hereby amended by adding a new Section 8.3 to the
end of said Article 8 which reads as follows:
8.3 Awards in Lieu of Annual Retainers. Each Non-employee Director
shall have the right to make an annual election to receive Shares (a
"Retainer Election") in lieu of all or a portion of an annual retainer for
Board service (the "Annual Retainer"). Such Retainer Election may be made
for the full amount of the Annual Retainer or in increments equal to the
number of regular Board Meetings scheduled for the Election Year (as
defined below).
(a) Retainer Election. A Non-employee Director may make a Retainer
Election on or before each annual stockholders meeting by written notice to
the Secretary of the Company specifying the amount of the Annual Retainer
(all or in increments set forth above) for which the Retainer Election is
being made. Such Retainer Election remains in effect for a one-year period
beginning on the day of the Annual Meeting of Stockholders at which such
Non-employee Director is elected or re-elected to the Board and ending on
the day before the next Annual Meeting of Stockholders (the "Election
Year"). Provided however, a Non-employee Director who is elected or
appointed to the Board at a time other than at the Annual Meeting of
Stockholders may make a Retainer Election by written notice to the
Secretary of the Company within ten (10) days after the date his term
begins and such election shall remain in effect for the remainder of the
Election Year.
(b) Issuance of Shares. After each regular Board meeting of an
Election Year, the Company shall award to each Non-employee Director who
made a Retainer Election applicable to such meeting, a number of Shares
(rounded to the nearest
<PAGE>
whole Share) determined by dividing (i) the incremental amount of the
Annual Retainer payable on the date of such meeting by (ii) the Fair Market
Value of a Share on the date of such meeting. Certificates for the Shares
awarded shall be issued to the recipient as soon as practicable and
thereupon the recipient shall have full voting, dividend and other
ownership rights with respect to such Shares.
Adopted by the Board of Directors of Plains Resources Inc. on May 21, 1998.
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PLAINS
RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET AS OF SEPTEMBER 30,
1998, AND CONSOLIDATED STATEMENT OF INCOME FOR THE NINE MONTHS ENDED SEPTEMBER
30, 1998 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> SEP-30-1998
<CASH> 7,887
<SECURITIES> 0
<RECEIVABLES> 113,828
<ALLOWANCES> 0
<INVENTORY> 29,020
<CURRENT-ASSETS> 151,241
<PP&E> 1,059,829
<DEPRECIATION> 201,139
<TOTAL-ASSETS> 1,032,116
<CURRENT-LIABILITIES> 157,177
<BONDS> 644,544
85,000
21,620
<COMMON> 1,685
<OTHER-SE> 116,438
<TOTAL-LIABILITY-AND-EQUITY> 1,032,116
<SALES> 775,993
<TOTAL-REVENUES> 776,732
<CGS> 713,764
<TOTAL-COSTS> 735,709
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 24,385
<INCOME-PRETAX> 8,942
<INCOME-TAX> 2,468
<INCOME-CONTINUING> 6,474
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<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 6,474
<EPS-PRIMARY> .24
<EPS-DILUTED> .22
</TABLE>
