<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 March 31, 1999
[ ] 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 [_]
16,911,713 shares of common stock $0.10 par value, issued and outstanding at
April 30, 1999.
Page 1 of 19
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
TABLE OF CONTENTS
- -------------------------------------------------------------------------------
PAGE
PART I. FINANCIAL INFORMATION
CONSOLIDATED FINANCIAL STATEMENTS:
Consolidated Balance Sheets:
March 31, 1999 and December 31, 1998................................ 3
Consolidated Statements of Income:
For the three months ended March 31, 1999 and 1998.................. 4
Consolidated Statements of Cash Flows:
For the three months ended March 31, 1999 and 1998.................. 5
Notes to Consolidated Financial Statements............................ 6
MANAGEMENT'S DISCUSSION AND ANALYSIS..................................... 10
PART II. OTHER INFORMATION.............................................. 18
Page 2 of 19
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except per share data)
<TABLE>
<CAPTION>
MARCH 31, DECEMBER 31,
1999 1998
---------------------------------
(unaudited)
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 889 $ 6,544
Accounts receivable 161,742 128,875
Inventory 28,826 42,520
Prepaid expenses and other 2,464 1,527
----------- ----------
Total current assets 193,921 179,466
----------- ----------
PROPERTY AND EQUIPMENT
Oil and natural gas properties - full cost method
Subject to amortization 612,609 596,203
Not subject to amortization 56,603 54,545
Crude oil pipeline, gathering and terminal assets 380,956 378,254
Other property and equipment 8,869 8,606
----------- ----------
1,059,037 1,037,608
Less allowance for depreciation, depletion and amortization (382,382) (375,882)
----------- ----------
676,655 661,726
----------- ----------
OTHER ASSETS 134,405 133,075
----------- ----------
$ 1,004,981 $ 974,267
=========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and other current liabilities $ 182,391 $ 170,985
Interest payable 3,190 7,950
Royalties payable 4,482 4,211
Notes payable and other current obligations 4,611 10,261
----------- ----------
Total current liabilities 194,674 193,407
BANK DEBT 76,800 52,000
BANK DEBT OF A SUBSIDIARY 181,000 175,000
SUBORDINATED DEBT 202,365 202,427
OTHER LONG-TERM DEBT 2,556 2,556
OTHER LONG-TERM LIABILITIES 7,678 13,967
----------- ----------
665,073 639,357
----------- ----------
MINORITY INTEREST 175,756 173,461
----------- ----------
SERIES E CUMULATIVE CONVERTIBLE PREFERRED STOCK,
STATED AT LIQUIDATION PREFERENCE 90,517 88,487
----------- ----------
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 $1,023,000 and
$1,354,000 at March 31, 1999 and December 31, 1998, respectively 22,277 21,946
Common Stock, $.10 par value, 50,000,000 shares authorized;
issued and outstanding 16,891,617 and 16,881,938 shares at 1,689 1,688
March 31, 1999 and December 31, 1998, respectively
Additional paid-in capital 124,815 124,679
Accumulated deficit (75,146) (75,351)
----------- ----------
73,635 72,962
----------- ----------
$ 1,004,981 $ 974,267
=========== ==========
</TABLE>
See notes to consolidated financial statements.
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(unaudited) (in thousands, except per share data)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
---------------------------
1999 1998
---------------------------
<S> <C> <C>
REVENUES
Oil and natural gas sales $ 21,142 $ 26,164
Marketing, transportation, storage and terminalling revenues 455,760 167,204
Interest and other income 69 204
---------- ---------
476,971 193,572
---------- ---------
EXPENSES
Production expenses 11,563 12,838
Marketing, transportation, storage and terminalling expenses 436,396 163,200
General and administrative 4,062 2,376
Depreciation, depletion and amortization 7,170 6,755
Interest expense 8,753 6,109
---------- ---------
467,944 191,278
---------- ---------
Income before income taxes and minority interest 9,027 2,294
Minority interest 4,820 -
---------- ---------
Income before income taxes 4,207 2,294
Income tax expense:
Current - 3
Deferred 1,641 860
---------- ---------
NET INCOME 2,566 1,431
Less: cumulative preferred stock dividends 2,361 312
---------- ---------
NET INCOME AVAILABLE TO COMMON STOCKHOLDERS $ 205 $ 1,119
========== =========
EARNINGS PER COMMON SHARE:
Basic $0.01 $0.07
========== =========
Diluted $0.01 $0.06
========== =========
</TABLE>
See notes to consolidated financial statements
Page 4 of 19
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited) (in thousands)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
----------------------------
1999 1998
------------ -----------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 2,566 $ 1,431
Items not affecting cash flows from operating activities:
Depreciation, depletion and amortization 7,170 6,755
Minority interest in income of a subsidiary 4,820 -
Deferred income taxes 1,641 860
Other non-cash items 390 54
Change in assets and liabilities from operating activities:
Accounts receivable (35,548) 27,749
Inventory 13,694 384
Prepaid expenses and other (937) (228)
Purchase of pipeline linefill (2,490) -
Accounts payable and other current liabilities 16,574 (18,881)
Interest payable (4,303) (4,308)
Royalties payable 271 13
---------- ----------
Net cash provided by operating activities 3,848 13,829
---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Payment for acquisition, exploration and developments costs (27,936) (15,944)
Payment for crude oil pipeline, gathering and terminal assets (2,702) -
Payment for additions to other property and assets (532) (315)
---------- ----------
Net cash used in investing activities (31,170) (16,259)
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt 78,300 75,560
Proceeds from short-term debt 4,250 750
Principal payments of long-term debt (47,500) (29,000)
Principal payments of short-term debt (9,900) (18,000)
Distribution to public Unitholders (2,525) -
Other (958) (688)
---------- ----------
Net cash provided by financing activities 21,667 28,622
---------- ----------
Net increase (decrease) in cash and cash equivalents (5,655) 26,192
Cash and cash equivalents, beginning of period 6,544 3,714
---------- ----------
Cash and cash equivalents, end of period $ 889 $ 29,906
========== ==========
</TABLE>
See notes to consolidated financial statements
Page 5 of 19
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 1999
(unaudited)
Note 1 -- Accounting Policies
The consolidated financial statements include the accounts of Plains Resources
Inc. (the "Company"), its wholly-owned subsidiaries and Plains All American
Pipeline, L.P. ("PAA") in which the Company has an approximate 57% ownership
interest. The operations of PAA are conducted through Plains Marketing, L.P. and
All American Pipeline, L.P. Plains All American Inc. ("PAAI"), a wholly owned
subsidiary of the Company, is the general partner ("General Partner") of PAA.
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, 1998, 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 March 31, 1999, 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.
Recent Accounting Pronouncement
In June 1998, the Financial Accounting Standards Board ("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 affected 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.
Note 2 -- Inventory and Other Assets
Inventory consists of the following:
March 31, December 31,
1999 1998
-------- -----------
(in thousands)
Crude oil $ 24,555 $ 37,702
Material and supplies 4,271 4,818
-------- --------
$ 28,826 $ 42,520
======== ========
Page 6 of 19
<PAGE>
Other assets consist of the following:
March 31, December,31
1999 1998
--------- -----------
(in thousands)
Pipeline linefill $ 57,001 $ 54,511
Deferred tax asset 46,738 47,785
Land 8,853 8,853
Debt issue costs 18,834 18,668
Other 9,027 8,245
--------- ---------
140,453 138,062
Accumulated amortization (6,048) (4,987)
--------- ---------
$ 134,405 $ 133,075
========= =========
Note 3 -- Acquisitions
On May 12, 1999, Plains Scurlock Permian, L.P. ("Plains Scurlock"), a newly
formed limited partnership of which PAAI is the general partner and Plains
Marketing, L.P. is the limited partner, completed the acquisition of Scurlock
Permian LLC and certain other pipeline assets from Marathon Ashland Petroleum
LLC (the "Scurlock Acquisition"). Including working capital adjustments and
associated closing and financing costs, the cash purchase price paid at closing
was approximately $146 million.
Scurlock Permian LLC, a wholly owned subsidiary of Marathon Ashland Petroleum
LLC, is engaged in crude oil transportation, trading and marketing, operating in
14 states with more than 2,400 miles of active pipelines, numerous storage
terminals and a fleet of more than 225 trucks. Its largest asset is an 800-mile
pipeline and gathering system located in the Spraberry Trend in West Texas that
extends into Andrews, Glasscock, Martin, Midland, Regan and Upton Counties,
Texas. The assets acquired also include approximately 2.4 million barrels of
crude oil used for working inventory.
Financing for the Scurlock Acquisition was provided through (i) Plains
Scurlock's limited recourse bank facility with BankBoston, N.A. (the "Plains
Scurlock Credit Facility"), (ii) the sale to the General Partner of 1.3 million
Class B Common Units of PAA at $19.125 per unit, the price equal to the market
value of PAA's common units and (ii) a $25 million draw under its existing
revolving credit agreement. The Plains Scurlock Credit Facility consists of (i)
a five year $130 million term loan and (ii) a three year $35 million revolving
credit facility.
The Plains Scurlock Credit Facility is nonrecourse to PAA, Plains Marketing,
L.P. and All American Pipeline, L.P. and is secured by the assets acquired.
Borrowings under the term loan bear interest at LIBOR plus 3% and under the
revolving credit facility at LIBOR plus 2.75%. A commitment fee equal to one-
half of one percent per year is charged on the unused portion of the revolving
credit facility. The term loan matures in May 2004 and the revolving credit
facility matures in May 2002. No principal payment is scheduled for amortization
prior to maturity.
In April 1999, PAA signed a definitive agreement to acquire a West Texas
crude oil pipeline and gathering system from Chevron Pipe Line Company for
approximately $40 million (the "Chevron Asset Acquisition"). Principal assets to
be acquired include approximately 400 miles of crude oil transmission lines,
associated gathering and lateral lines and three million barrels of crude oil
storage and terminalling capacity in Crane, Ector, Midland, Upton, Ward and
Winkler Counties, Texas. Closing of the transaction is subject to regulatory
review and approval, consents from third parties, and customary due diligence.
Subject to satisfaction of the foregoing conditions, the transaction is expected
to close early in the third quarter of 1999. It is anticipated that the Chevron
Asset Acquisition will be made by Plains Scurlock, with financing provided by
the Plains Scurlock Credit Facility.
Chevron will continue transporting crude oil through the pipeline under a
contractual arrangement. PAA will also enter into a five-year contractual
arrangement to sell up to 30,000 barrels of crude oil per day at market prices
to another Chevron entity. Such arrangement may be extended by Chevron for up to
five additional years. The system is currently moving an aggregate of
approximately 98,000 barrels of crude oil per day under various gathering and
transportation arrangements.
Page 7 of 19
<PAGE>
On July 30, 1998, PAAI 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 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
and the remaining $85 million was provided by the issuance of the Company's
Series E Preferred Stock.
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 net income per share as if the acquisition
occurred on January 1, 1998.
Three Months Ended
March 31, 1998
-------------------
(in thousands,
except per share data)
Revenues $ 385,000
==========
Net income $ 6,543
==========
Net income per share:
Basic $ 0.11
==========
Diluted $ 0.10
==========
Note 4 -- 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 months ended March 31, 1999 and 1998, as
required by Statement of Financial Accounting Standards No. 128, Earnings Per
Share.
<TABLE>
<CAPTION>
For the Quarter Ended March 31,
--------------------------------------------------------------------------
1999 1998
------------------------------------- ---------------------------------
Per Per
Income Shares Share Income Shares Share
(Numerator) (Denominator) Amount (Numerator) (Denominator) Amount
---------- ----------- --------- ----------- ----------- -------
(in thousands, except per share data)
<S> <C> <C> <C> <C> <C> <C>
Net income $ 2,566 $ 1,431
Less: preferred stock dividends (2,361) (312)
-------- ---------
Income available to common stockholders 205 16,890 $ 0.01 1,119 16,724 $ 0.07
========= =========
Effect of dilutive securities:
Employee stock options - 628 - 1,029
Warrants - 393 - 518
-------- -------- --------- --------
Income available to common
stockholders assuming dilution $ 205 17,911 $ 0.01 $ 1,119 18,271 $ 0.06
======== ======== ========= ========= ======== =========
</TABLE>
Certain options and warrants to purchase shares of the Company's common stock
("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 preferred stock is convertible into Common Stock but was
not included in the computation of diluted EPS because the effect was
antidilutive.
Page 8 of 19
<PAGE>
Note 5 -- Operating Segments
The Company's operations consist of two operating segments: (1) Upstream
Operations - engages in the acquisition, exploitation, development, exploration
and production of crude oil and natural gas and (2) Midstream Operations -
engages in crude oil gathering, marketing, terminalling, storage and
transportation. The Company evaluates segment performance based on gross margin,
gross profit and income before income taxes and minority interest.
(In thousands) Upstream Midstream Total
----------------------------------------------------------------------------
For the Three Months Ended March 31, 1999
Revenues:
External Customers $ 21,142 $ 455,760 $476,902
Intersegment (a) - 327 327
Other income (expense) (28) 97 69
-------- --------- --------
Total revenues of reportable segments $ 21,114 $ 456,184 $477,298
======== ========= ========
Segment gross margin (b) $ 9,579 $ 19,364 $ 28,943
Segment gross profit (c) 7,968 16,913 24,881
Segment income/(loss) before income taxes
and minority interest (1,959) 10,986 9,027
----------------------------------------------------------------------------
For the Three Months Ended March 31, 1998
Revenues:
External Customers $ 26,164 $ 167,204 $193,368
Intersegment (a) - 257 257
Interest income 27 177 204
-------- --------- --------
Total revenues of reportable segments $ 26,191 $ 167,638 $193,829
======== ========= ========
Segment gross margin (b) $ 13,326 $ 4,004 $ 17,330
Segment gross profit (c) 11,936 3,018 14,954
Segment income before income taxes
and minority interest 301 1,993 2,294
----------------------------------------------------------------------------
(a) Intersegment revenues and transfers were conducted on an arm's-length
basis.
(b) Gross margin is calculated as operating revenues less operating
expenses.
(c) Gross profit is calculated as operating revenues less operating
expenses and general and administrative expenses.
Page 9 of 19
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
General
On November 23, 1998, Plains All American Pipeline, L.P. ("PAA"), through which
the Company's midstream activities are conducted, completed its initial public
offering of 13.1 million common units representing limited partner interests.
PAA's results are consolidated into the Company's results with the public's 43%
ownership reflected as a minority interest deduction from income. The operations
of PAA are conducted through Plains Marketing, L.P. and All American Pipeline,
L.P. Plains All American Inc. ("PAAI"), a wholly owned subsidiary of the Company
is the general partner ("General Partner") of PAA. PAA was formed to acquire the
midstream crude oil business and assets of the Company, including the All
American Pipeline and the SJV Gathering System, which the Company purchased from
Goodyear in July 1998 (the "All American Pipeline Acquisition"). 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 3 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, 1998.
Results of Operations
Three month periods ended March 31, 1999 and 1998
The Company reported net income for the first quarter of 1999 of $2.6 million as
compared with net income of $1.4 million, or $0.07 per common share ($0.06
assuming dilution) in the 1998 first quarter. After deducting accrued preferred
stock dividends, net income per common share was $0.01 per common share in the
1999 first quarter (also $0.01 per share assuming dilution). Cash flow from
operations (net income before noncash expenses) increased approximately 29% to
$11.8 million in the 1999 period as compared to $9.1 million in the first
quarter of 1998. Earnings before interest, taxes, depreciation, amortization and
minority interest ("EBITDA") increased 65% to $25.0 million versus $15.2 million
in the first quarter of 1998. Net cash provided by operating activities, as
reported in the consolidated statements of cash flows was $3.8 million for the
three months ended March 31, 1999, as compared to $13.8 million for the 1998
comparative period. The decrease is primarily attributable to (i) the purchase
of approximately $2.5 million of pipeline linefill and the payment of
approximately $2.5 million of property taxes related to pipeline operations in
the 1999 first quarter and (ii) the sale of crude oil inventory during the first
quarter of 1999 for which payment was received during the second quarter.
Upstream Results
The following table sets forth certain upstream operating information of the
Company for the periods presented:
Three Months Ended
March 31,
------------------
1999 1998
-------- -------
(in thousands)
Average Daily Production Volumes
Barrels of oil equivalent ("BOE")
California (approximately 91% oil) 14.9 13.7
Gulf Coast (100% oil) 2.9 4.9
Illinois Basin (100% oil) 3.2 3.7
-------- -------
Total (approximately 94% oil) 21.0 22.3
======== =======
Unit Economics
Average sales price per BOE $11.21 $13.03
Production expense per BOE 6.13 6.39
-------- -------
Gross margin per BOE 5.08 6.64
Upstream G&A expense per BOE 0.85 0.69
-------- -------
Gross profit per BOE $ 4.23 $ 5.95
======== =======
During the 1999 first quarter, production volumes were affected by shut-ins and
production cutbacks related to lower prices and curtailments related to refinery
disruptions in California as well as declines in the Company's Gulf Coast
production. As a result, total oil equivalent production decreased approximately
6% to an average of 21,000 BOE per day as compared to the first quarter 1998
average of 22,300 barrels per day. Excluding production from the Mt. Poso Field,
which was acquired in the fourth quarter of 1998, total production decreased
approximately 10% from the prior year quarter. Net daily production in
California increased approximately 9% to 14,900 BOE in the first quarter of 1999
compared to 13,700 BOE in the same quarter of 1998. Excluding production from
the Mt. Poso field, total California production was up
Page 10 of 19
<PAGE>
approximately 3% over the comparative prior year quarter. Net daily production
for the Company's Gulf Coast properties averaged approximately 2,900 barrels per
day during the first quarter of 1999, compared to 4,900 barrels per day in the
1998 comparative period. Net daily production in the Illinois Basin averaged
approximately 3,200 barrels per day during the first quarter of 1999, a decrease
of approximately 14% as compared to the 1998 first quarter average of 3,700
barrels per day.
Oil and natural gas revenues were $21.1 million for the first quarter of 1999,
a decrease of approximately 19% from the 1998 first quarter amount of $26.2
million. The decrease is due to decreased crude oil prices and the production
decreases discussed above. 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 $11.21 per
BOE, a decrease of approximately 14% as compared to the 1998 first quarter
average wellhead price of $13.03 per BOE. The NYMEX benchmark West Texas
Intermediate ("WTI") crude oil price averaged $13.06 per barrel during the first
quarter of 1999, or nearly $3.00 per barrel below the $15.97 per barrel average
for the first quarter of 1998 and $9.77 below the $22.83 in the first quarter of
1997. The Company maintained hedges on approximately 45% and 60% of its crude
oil production in the first quarter of 1999 and 1998, respectively, with the
hedge price averaging a NYMEX WTI price of approximately $18.25 per barrel and
$19.80 per barrel in the respective periods. Hedging transactions had the effect
of increasing the Company's average price per BOE by $2.21 and $2.10 in the
first quarter of 1999 and 1998, respectively.
Unit production expenses averaged $6.13 per BOE, a 4% decrease as compared to
the 1998 first quarter average of $6.39 per BOE. Unit gross margin in the
upstream segment was $5.08 per BOE, a 23% decrease as compared to $6.64 per BOE
reported for the first quarter of 1998 on substantially higher oil prices.
Upstream unit gross profit, which deducts all pre-interest cash costs, was $4.23
per BOE, 29% lower than the 1998 amount of $5.95 per BOE. Total production
expenses decreased to $11.6 million from $12.8 million for the first quarter of
1998.
Unit general and administrative ("G&A") expenses in the upstream segment were
$0.85 per BOE in the first quarter of 1999, compared to $0.69 per BOE in the
prior year comparative quarter. The increase is primarily due to decreased
production volumes, increased public company expenses and the Company's upstream
activity. Depreciation, depletion and amortization ("DD&A") per BOE was $2.10
for the first quarter of 1999 compared to $3.00 per BOE in the 1998 comparative
quarter. Such decrease is primarily due to a $174 million reduction in the
carrying cost of the Company's proved oil and natural gas properties recorded in
the 1998 fourth quarter due to low crude oil prices, and the impact of
subsequent price recovery on proved reserve volumes. The NYMEX WTI price was
$12.05 per barrel at December 31, 1998, compared to $16.76 at March 31, 1999.
Total upstream DD&A expense was $4.0 million in the first quarter of 1999,
compared to $6.0 million in the 1998 comparative quarter due to the lower per
unit rate and decreased production volumes.
Midstream Results
The following table sets forth certain midstream operating information of the
Company for the periods presented:
Three Months Ended
March 31,
------------------
1999 1998
-------- -------
(in thousands)
Operating Results:
Gross margin
Pipeline $ 11,882 $ -
Terminalling and storage
and gathering and marketing 7,482 4,004
-------- -------
Total 19,364 4,004
General and administrative expense (2,451) (986)
-------- -------
Gross profit $ 16,913 $ 3,018
======== =======
Average Daily Volumes (barrels)
Pipeline tariff activities 126 -
Pipeline margin activities 47 -
-------- -------
Total 173 -
======== =======
Lease gathering 99 81
Bulk purchases 94 95
Terminal throughput 75 66
Pipeline Operations. The Company's results for the first quarter of 1998 do not
include the results of operations of the All American Pipeline and the SJV
Gathering System which were acquired effective July 30, 1998. Gross margin from
pipeline
Page 11 of 19
<PAGE>
activities was $11.9 million for the first quarter of 1999. Tariff revenues were
$13.1 million and are primarily attributable to transport volumes from the Santa
Ynez field and the Point Arguello field. Volumes related to margin activities
averaged approximately 47,000 barrels per day. The margin between revenue and
direct cost of crude purchased was $5.0 million for the first quarter of 1999.
Operations and maintenance expenses were $3.0 million for such period.
The following table sets forth the All American Pipeline average deliveries per
day within and outside California for the three months ended March 31, 1999.
Deliveries:
Average daily volumes (thousand barrels):
Within California 112
Outside California 61
----
Total 173
====
Terminalling and Storage Activities and Gathering and Marketing Activities.
Gross margin from terminalling and storage and gathering and marketing
activities was $7.5 million for the quarter ended March 31, 1999, reflecting a
87% increase over the $4.0 million reported for the 1998 period. Net of interest
expense associated with contango inventory transactions, gross margin for the
first quarter of 1999 was $7.3 million, representing an increase of
approximately 90% over the 1998 first quarter amount, likewise net of contango
interest. The increase in gross margin was primarily attributable to an increase
in the volumes gathered and marketed in West Texas, Louisiana and the Gulf of
Mexico and activities at the Cushing Terminal.
General
Total G&A expenses, including midstream activities, were approximately $4.1
million for the three months ended March 31, 1999, an increase of $1.7 million
as compared to the 1998 comparative period. Approximately $1.5 million of the
increase is attributable to the Company's midstream activities. Approximately
$1.2 million of the midstream increase is associated with the July 1998 All
American Pipeline Acquisition and expenses incurred by PAA as a result of its
being a separate public entity. An additional $0.3 million is due to a one time
expense related to a staff reduction and relocation of certain functions related
to the midstream segment's pipeline operations. Interest expense for the quarter
ended March 31, 1999 increased to $8.8 million from $6.1 million for the
comparative prior year quarter primarily due to the debt incurred for the All
American Pipeline Acquisition. Capitalized interest was $1.0 million and $0.9
million for the three months ended March 31, 1999 and 1998, respectively.
During the first quarter of 1999, the Company reported a minority interest
deduction from income of approximately $4.8 million. Such amount represents the
public's 43% share in the earnings of PAA. The Company's total tax provision for
the quarter ended March 31, 1999, was approximately $1.6 million, as compared to
the first quarter 1998 tax provision of approximately $0.9 million. Such
increase is due to the increase in income before taxes between the two periods.
In both periods, substantially all of the Company's income tax provision was
deferred.
In June 1998, the Financial Accounting Standards Board ("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 affected 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 results of operations or financial position.
Page 12 of 19
<PAGE>
Capital Resources, Liquidity and Financial Condition
Acquisitions
On May 12, 1999, Plains Scurlock Permian, L.P. ("Plains Scurlock"), a newly
formed limited partnership of which PAAI is the general partner and Plains
Marketing, L.P. is the limited partner, completed the acquisition of Scurlock
Permian LLC and certain other pipeline assets from Marathon Ashland Petroleum
LLC (the "Scurlock Acquisition"). Including working capital adjustments and
associated closing and financing costs, the cash purchase price paid at closing
was approximately $146 million.
Scurlock Permian LLC, a wholly owned subsidiary of Marathon Ashland Petroleum
LLC, is engaged in crude oil transportation, trading and marketing, operating in
14 states with more than 2,400 miles of active pipelines, numerous storage
terminals and a fleet of more than 225 trucks. Its largest asset is an 800-mile
pipeline and gathering system located in the Spraberry Trend in West Texas that
extends into Andrews, Glasscock, Martin, Midland, Regan and Upton Counties,
Texas. The assets acquired also include approximately 2.4 million barrels of
crude oil used for working inventory.
Financing for the Scurlock Acquisition was provided through (i) Plains
Scurlock's limited recourse bank facility with BankBoston, N.A. (the "Plains
Scurlock Credit Facility"), (ii) the sale to the General Partner of 1.3 million
Class B Common Units of PAA at $19.125 per unit, the price equal to the market
value of PAA's common units and (ii) a $25 million draw under its existing
revolving credit agreement. The Plains Scurlock Credit Facility consists of (i)
a five year $130 million term loan and (ii) a three year $35 million revolving
credit facility.
The Plains Scurlock Credit Facility is nonrecourse to PAA, Plains Marketing,
L.P. and All American Pipeline, L.P. and is secured by the assets acquired.
Borrowings under the term loan bear interest at LIBOR plus 3% and under the
revolving credit facility at LIBOR plus 2.75%. A commitment fee equal to one-
half of one percent per year is charged on the unused portion of the revolving
credit facility. The term loan matures in May 2004 and the revolving credit
facility matures in May 2002. No principal payment is scheduled for amortization
prior to maturity.
In April 1999, PAA signed a definitive agreement to acquire a West Texas
crude oil pipeline and gathering system from Chevron Pipe Line Company for
approximately $40 million (the "Chevron Asset Acquisition"). Principal assets to
be acquired include approximately 400 miles of crude oil transmission lines,
associated gathering and lateral lines and three million barrels of crude oil
storage and terminalling capacity in Crane, Ector, Midland, Upton, Ward and
Winkler Counties, Texas. Closing of the transaction is subject to regulatory
review and approval, consents from third parties, and customary due diligence.
Subject to satisfaction of the foregoing conditions, the transaction is expected
to close early in the third quarter of 1999. It is anticipated that the Chevron
Asset Acquisition will be made by Plains Scurlock, with financing provided by
the Plains Scurlock Credit Facility.
Chevron will continue transporting crude oil through the pipeline under a
contractual arrangement. PAA will also enter into a five-year contractual
arrangement to sell up to 30,000 barrels of crude oil per day at market prices
to another Chevron entity. Such arrangement may be extended by Chevron for up to
five additional years. The system is currently moving an aggregate of
approximately 98,000 barrels of crude oil per day under various gathering and
transportation arrangements.
PAA Distributions
PAA will distribute 100% of its Available Cash within 45 days after the end of
each quarter to Unitholders of record and to the General Partner. Available Cash
is generally defined as all cash and cash equivalents of PAA on hand at the end
of each quarter less reserves established by the General Partner for future
requirements. Distributions of Available Cash to holders of Subordinated Units
are subject to the prior rights of holders of Common Units to receive the
minimum quarterly distribution ("MQD") for each quarter during the subordination
period (which will not end earlier than December 31, 2003) and to receive any
arrearages in the distribution of the MQD on the Common Units for the prior
quarters during the subordination period. The MQD is $0.45 per unit ($1.80 per
unit on an annual basis). Approximately 10 million of the 17 million Units held
by PAAI are Subordinated Units. Upon expiration of the Subordination Period, all
Subordinated Units will be converted on a one-for-one basis into Common Units
and will participate pro rata with all other Common Units in future
distributions of Available Cash. Under certain circumstances, up to 50% of the
Subordinated Units may convert into Common Units prior to the expiration of the
Subordination Period. Common Units will not accrue arrearages with respect to
distributions for any quarter after the Subordination Period and Subordinated
Units will not accrue any arrearages with respect to distributions for any
quarter.
Page 13 of 19
<PAGE>
If quarterly distributions of Available Cash exceed the MQD or the Target
Distribution Levels (as defined), the General Partner will receive distributions
which are generally equal to 15%, then 25% and then 50% of the distributions of
Available Cash that exceed the MQD or Target Distribution Level. The Target
Distribution Levels are based on the amounts of Available Cash from PAA's
Operating Surplus (as defined) distributed with respect to a given quarter that
exceed distributions made with respect to the MQD and Common Unit arrearages, if
any.
On February 12, 1999, PAA paid a cash distribution of $0.193 per unit on its
outstanding Common Units and Subordinated Units. The $5.8 million distribution
was paid to all Unitholders of record at the close of business on January 29,
1999. A distribution of approximately $3.4 million was paid to the Company for
its limited partner and general partner interests with the remainder being
distributed to PAA's public Unitholders. The distributions represented a partial
quarterly distribution for the 39-day period from November 23, 1998, the closing
of the IPO, through December 31, 1998.
On April 19, 1999, PAA declared a cash distribution of $0.45 per unit on its
outstanding Common Units and Subordinated Units. This distribution is the first
full quarterly distribution since PAA was formed. The distribution is payable on
May 14, 1999, to holders of record of Common Units and Subordinated Units at the
close of business on May 3, 1999. The Company's share of the distribution will
be approximately $7.8 million.
Credit Facilities
The Company has a $225 million revolving credit facility (the "Revolving Credit
Facility") with a group of banks (the "Lenders"). The Revolving Credit Facility
is guaranteed by all of the Company's upstream subsidiaries and is
collateralized by the oil and gas properties of the Company and the guaranteeing
subsidiaries and the stock of all upstream subsidiaries. The borrowing base
under the Revolving Credit Facility at March 31, 1999, is $225 million and is
subject to redetermination from time to time by the Lenders in good faith, in
the exercise of the Lenders' sole discretion, and in accordance with customary
practices and standards in effect from time to time for oil and natural gas
loans to borrowers similar to the Company. Such borrowing base may be affected
from time to time by the performance of the Company's oil and natural gas
properties and changes in oil and natural gas prices. The Company incurs a
commitment fee of 3/8% per annum on the unused portion of the borrowing base.
The Revolving Credit Facility, as amended, matures on July 1, 2000, at which
time the remaining outstanding balance converts to a term loan which is
repayable in twenty equal quarterly installments commencing October 1, 2000,
with a final maturity of July 1, 2005. The Revolving Credit Facility bears
interest, at the Company's option of either LIBOR plus 1 3/8% or Base Rate (as
defined therein). At March 31, 1999, outstanding borrowings under the Revolving
Credit Facility were approximately $77 million.
Concurrently with the closing of the IPO, PAA entered into a $225 million bank
credit agreement (the "Bank Credit Agreement") that includes a $175 million term
loan facility (the "Term Loan Facility") and a $50 million revolving credit
facility (the "PAA Revolving Credit Facility"). PAA may borrow up to $50 million
under the PAA Revolving Credit Facility for acquisitions, capital improvements,
working capital and general business purposes. At March 31, 1999, PAA had $175
million outstanding under the Term Loan Facility, representing indebtedness
assumed from the General Partner and $6.0 million outstanding under the PAA
Revolving Credit Facility. The Term Loan Facility matures in 2005, and no
principal is scheduled for payment prior to maturity. The Term Loan Facility may
be prepaid at any time without penalty. The PAA Revolving Credit Facility
expires in November 2000.
PAA has a $175 million letter of credit and borrowing facility (the "Letter of
Credit Facility"), the purpose of which is to provide (i) standby letters of
credit to support the purchase and exchange of crude oil for resale and (ii)
borrowings to finance crude oil inventory which has been hedged against future
price risk or designated as working inventory. Aggregate availability under the
Letter of 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 PAA, primarily crude oil inventory and accounts
receivable and accounts payable related to the purchase and sale of crude oil.
At March 31, 1999, the borrowing base under the Letter of Credit Facility was
$175 million. The Letter of Credit Facility has a $40 million sublimit for
borrowings to finance crude oil purchased in connection with operations at PAA's
crude oil terminal and storage facilities. At March 31, 1999, there were letters
of credit of approximately $73 million and borrowings of $4.1 million
outstanding under the Letter of Credit Facility.
Page 14 of 19
<PAGE>
Investing and Financing Activities
At March 31, 1999, the Company had a working capital deficit of approximately
$0.8 million compared to a working capital deficit of $13.9 million at December
31, 1998. The Company has historically operated with a working capital deficit
due primarily to ongoing capital expenditures that have been financed through
cash flow and the Revolving Credit Facility.
Net cash flows used in investing activities were $31.2 million and $16.3 million
for the three months ended March 31, 1999, and 1998, respectively. Investing
activities include payments for acquisition, exploration and development costs
of $27.9 million and $15.9 million for the three months ended March 31, 1999 and
1998, respectively. Investing activities for the first quarter of 1999 include
payments for crude oil pipeline, gathering and terminal assets of approximately
$2.7 million, including approximately $2.4 million related to the expansion of
the Company's crude oil terminal and storage facility in Cushing, Oklahoma (the
"Cushing Terminal").
Net cash provided by financing activities amounted to $21.7 million and $28.6
million for the three months ended March 31, 1999 and 1998, respectively.
Included in both years are net proceeds from borrowings under the Revolving
Credit Facility as a result of acquisition, exploration and development
activities. Financing activities include approximately $4.3 million and $0.8
million in short-term borrowings for the three months ended March 31, 1999 and
1998, respectively, and approximately $9.9 million and $18 million of repayments
for the respective periods, related to contango crude oil inventory transactions
at the Cushing Terminal.
Changing Oil and Natural Gas Prices
The Company's upstream activities are 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, substantial future crude oil price declines would adversely affect 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.
The Company has entered into various fixed price arrangements which provide the
Company with downside price protection on approximately 13,000 barrels of oil
per day at a NYMEX WTI crude oil price of approximately $17.45 per barrel for
April 1, 1999, through June 30, 1999, and approximately 13,000 barrels of oil
per day at a NYMEX WTI crude oil price of $18.30 per barrel for July 1, 1999,
through December 31, 1999. Thus, based on the Company's average first quarter
1999 crude oil production rate, these arrangements generally provide the Company
with downside price protection for approximately 65% of its crude oil
production. For 2000, the Company has entered into various arrangements which
will provide for it to receive a minimum price of approximately $15.00 per
barrel on 6,000 barrels per day (equivalent to 30% of first quarter 1999 crude
oil production levels). Approximately two thirds of the volumes subject to these
arrangements will participate in price increases above the $15.00 floor price,
subject to a ceiling limitation of $20.00 per barrel. The foregoing NYMEX WTI
crude oil 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.
Year 2000
Year 2000 Issue. Some 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,
because the Company directly depends on its own applications, equipment and
systems and indirectly depends 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 six 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, (v) implementation of the necessary modifications and
(vi) contingency planning. 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
Page 15 of 19
<PAGE>
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 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
substantially complete. The Company has retained a Year 2000 consulting firm
which is currently identifying and evaluating field equipment which has embedded
chip systems. 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 completed within the third quarter of
1999.
Contingency Planning. As part of the Year 2000 project, the Company will seek to
determine which of its business activities may be vulnerable to a Year 2000
disruption. Appropriate contingency plans will then be developed for each "at
risk" business activity to provide an alternative means of functioning which
minimizes the effect of the potential Year 2000 disruption, both internally and
on those with whom it does business. Such contingency plans are expected to be
completed by the fourth quarter of 1999.
Costs to Address Year 2000 Compliance Issues. Through March 31, 1999, the
Company has expended approximately $440,000 in its Year 2000 project, excluding
costs borne by PAA. While the total cost to the Company of the Year 2000 project
is still being evaluated, the Company currently estimates that the costs to be
incurred in 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 $350,000 and $450,000. The
Company expects to fund these expenditures with cash from operations or
borrowings. Based upon these estimates, the Company does not expect the costs of
its Year 2000 project to have a material adverse effect on its financial
position, results of operation or cash flows.
Risk of Non-Compliance. The major applications that 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 SCADA computer systems 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.
While the Company believes that its Year 2000 project will substantially reduce
the risks associated with the Year 2000 issue, there can be no assurance that it
will be successful in completing each and every aspect of the project on
schedule, and if successful, the project will have the expected results. Due to
the general uncertainity inherent in the Year 2000 issues, the Company cannot
conclude that its failure or the failure of third parties to achieve Year 2000
compliance will not adversely affect its financial position, results of
operations or cash flows.
Page 16 of 19
<PAGE>
Quantitative and Qualitative Disclosures about Market Risks
The Company is exposed to various market risks, including volatility in crude
oil and natural gas commodity prices and interest rates. To manage such
exposure, the Company enters into various derivative transactions. The Company
does not enter into derivative transactions for speculative trading purposes.
Substantially all the Company's derivative contracts are exchange traded or with
major financial institutions and the risk of credit loss is considered remote.
The fair value of outstanding derivative commodity instruments and the change in
fair value that would be expected from a 10 percent adverse price change are
shown in the table below:
Change in Fair
Fair Value from 10%
At March 31, 1999 Value Adverse Price Change
-------------------------- ----------- --------------------
(in millions)
Crude Oil
Swaps $ 6.2 $ (5.9)
Futures contracts (2.6) (4.9)
At March 31, 1999, the discussion of the Company's interest rate risk has not
changed materially from that presented in the Company's Annual Report on Form
10-K for the year ended December 31, 1998.
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, 1998.
Page 17 of 19
<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
27. Financial Data Schedule
B. Report on Form 8-K
None
Page 18 of 19
<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: May 14, 1999 By: /s/ Cynthia A. Feeback
-----------------------------
Cynthia A. Feeback, Controller;
Assistant Treasurer and
Principal Accounting Officer
(Principal Accounting Officer)
Page 19 of 19
<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 MARCH 31, 1999,
AND CONSOLIDATED STATEMENT OF INCOME FOR THE THREE MONTHS ENDED MARCH 31, 1999,
AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> MAR-31-1999
<CASH> 889
<SECURITIES> 0
<RECEIVABLES> 161,742
<ALLOWANCES> 0
<INVENTORY> 28,826
<CURRENT-ASSETS> 193,921
<PP&E> 1,059,037
<DEPRECIATION> 382,382
<TOTAL-ASSETS> 1,004,981
<CURRENT-LIABILITIES> 194,674
<BONDS> 462,721
90,517
22,277
<COMMON> 1,689
<OTHER-SE> 49,669
<TOTAL-LIABILITY-AND-EQUITY> 1,004,981
<SALES> 476,902
<TOTAL-REVENUES> 476,971
<CGS> 447,959
<TOTAL-COSTS> 455,129
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 8,753
<INCOME-PRETAX> 4,207
<INCOME-TAX> 1,641
<INCOME-CONTINUING> 2,566
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 2,566
<EPS-PRIMARY> .01
<EPS-DILUTED> .01
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