<PAGE>
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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, 2000
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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 [_]
17,493,468 shares of common stock $0.10 par value, issued and outstanding at
November 8, 2000.
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<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
TABLE OF CONTENTS
PAGE
PART I. FINANCIAL INFORMATION
CONSOLIDATED FINANCIAL STATEMENTS:
Consolidated Balance Sheets:
September 30, 2000 and December 31, 1999.......................... 3
Consolidated Statements of Operations:
For the three and nine months ended September 30, 2000 and 1999... 4
Consolidated Statements of Cash Flows:
For the nine months ended September 30, 2000 and 1999............. 5
Notes to Consolidated Financial Statements............................. 6
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS............................... 22
PART II. OTHER INFORMATION............................................. 35
2
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
--------------- ---------------
(unaudited)
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 9,866 $ 68,228
Accounts receivable and other current assets 411,539 521,948
Inventory 29,548 40,478
Assets held for sale (Note 4) - 141,486
---------- ----------
Total current assets 450,953 772,140
---------- ----------
PROPERTY AND EQUIPMENT
Oil and natural gas properties - full cost method
Subject to amortization 718,879 671,928
Not subject to amortization 55,436 52,031
Crude oil pipeline, gathering and terminal assets 465,247 458,502
Other property and equipment 9,061 7,706
---------- ----------
1,248,623 1,190,167
Less allowance for depreciation, depletion and amortization (429,874) (402,514)
---------- ----------
818,749 787,653
---------- ----------
OTHER ASSETS 102,179 129,767
---------- ----------
$1,371,881 $1,689,560
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and other current liabilities $ 418,719 $ 546,393
Notes payable and other current obligations 511 109,880
---------- ----------
Total current liabilities 419,230 656,273
BANK DEBT 13,000 137,300
BANK DEBT OF A SUBSIDIARY 292,000 259,450
SUBORDINATED DEBT 277,639 277,909
OTHER LONG-TERM DEBT 1,533 2,044
OTHER LONG-TERM LIABILITIES AND DEFERRED CREDITS 3,740 21,107
---------- ----------
1,007,142 1,354,083
---------- ----------
MINORITY INTEREST 166,655 156,045
---------- ----------
CUMULATIVE CONVERTIBLE PREFERRED STOCK,
STATED AT LIQUIDATION PREFERENCE 137,721 138,813
---------- ----------
NON-REDEEMABLE PREFERRED STOCK, COMMON STOCK
AND OTHER STOCKHOLDERS' EQUITY
Series D Cumulative Convertible Preferred Stock 23,300 23,300
Common Stock 1,814 1,792
Additional paid-in capital 132,782 130,027
Accumulated deficit (93,312) (114,500)
Treasury stock, at cost (4,221) -
---------- ----------
60,363 40,619
---------- ----------
$ 1,371,881 $ 1,689,560
=========== ===========
</TABLE>
See notes to consolidated financial statements.
3
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
(unaudited)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------- ----------------------------
2000 1999 2000 1999
------------- ------------- ------------- ------------
(restated) (restated)
<S> <C> <C> <C> <C>
REVENUES
Oil and natural gas sales $ 38,610 $ 34,654 $ 109,192 $ 80,985
Marketing, transportation, storage
and terminalling revenues 703,944 1,098,506 2,347,826 2,416,116
Gain on sale of assets (Note 4) - - 48,188 -
Interest and other income 689 359 7,278 666
-------- ---------- ---------- ----------
743,243 1,133,519 2,512,484 2,497,767
-------- ---------- ---------- ----------
EXPENSES
Production expenses 15,934 16,326 46,612 39,989
Marketing, transportation, storage
and terminalling expenses 671,791 1,066,567 2,247,163 2,338,873
Unauthorized trading losses
and related expenses (Note 3) 6,600 72,250 6,600 114,925
General and administrative 9,832 8,898 31,296 20,615
Noncash compensation expense 2,138 1,947 2,269 1,947
Depreciation, depletion and amortization 10,768 10,108 36,064 25,553
Interest expense 13,095 13,151 41,912 32,668
-------- ---------- ---------- ----------
730,158 1,189,247 2,411,916 2,574,570
-------- ---------- ---------- ----------
Income (loss) before income taxes,
minority interest and extraordinary item 13,085 (55,728) 100,568 (76,803)
Minority interest 2,047 (23,786) 39,451 (32,014)
-------- ---------- ---------- ----------
Income (loss) before income taxes
and extraordinary item 11,038 (31,942) 61,117 (44,789)
Income tax expense (benefit)
Current 220 - 741 -
Deferred 4,084 (11,895) 23,094 (16,465)
-------- ---------- ---------- ----------
Income (loss) before extraordinary item 6,734 (20,047) 37,282 (28,324)
Extraordinary item, net of tax benefit
and minority interest - - (4,988) -
-------- ---------- ---------- ----------
NET INCOME (LOSS) 6,734 (20,047) 32,294 (28,324)
Less: cumulative preferred stock dividends 3,694 2,493 11,106 7,327
-------- ---------- ---------- ----------
NET INCOME (LOSS) AVAILABLE
TO COMMON STOCKHOLDERS $ 3,040 $ (22,540) $ 21,188 $ (35,651)
======== ========== ========== ==========
Basic earnings (loss) per share
Income (loss) before extraordinary item $ 0.17 $ (1.30) $ 1.46 $ (2.09)
Extraordinary item - - (0.28) -
-------- ---------- ---------- ----------
Net income (loss) $ 0.17 $ (1.30) $ 1.18 $ (2.09)
======== ========== ========== ==========
Diluted earnings (loss) per share
Income (loss) before extraordinary item $ 0.16 $ (1.30) $ 1.26 $ (2.09)
Extraordinary item - - (0.17) -
-------- ---------- ---------- ----------
Net income (loss) $ 0.16 $ (1.30) $ 1.09 $ (2.09)
======== ========== ========== ==========
</TABLE>
See notes to consolidated financial statements.
4
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
-----------------------------
2000 1999
------------- --------------
(restated)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 32,294 $ (28,324)
Items not affecting cash flows from operating activities:
Depreciation, depletion and amortization 36,064 25,553
Gain on sale of assets (Note 4) (48,188) -
Minority interest in income of a subsidiary 32,484 (32,014)
Deferred income taxes 19,904 (16,465)
Other noncash items 12,903 3,168
Change in assets and liabilities from operating activities:
Accounts receivable and other current assets 79,684 (159,561)
Inventory 10,930 (37,551)
Pipeline linefill (13,397) (3)
Accounts payable and other current liabilities (137,204) 242,290
Other long-term liabilities and deferred credits (8,000) 10,873
----------- --------
Net cash provided by operating activities 17,474 7,966
----------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Costs incurred in connection with acquisitions - (173,070)
Payments for crude oil pipeline, gathering and terminal assets (6,859) (7,785)
Payments for acquisition, exploration and development costs (49,850) (57,692)
Payments for additions to other property and assets (2,205) (469)
Proceeds from sale of assets (Note 4) 223,859 -
----------- --------
Net cash provided by (used in) investing activities 164,945 (239,016)
----------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt 921,825 508,321
Proceeds from short-term debt 47,750 42,150
Principal payments of long-term debt (1,064,736) (286,132)
Principal payments of short-term debt (106,469) (21,650)
Purchase of treasury stock (4,221) -
Proceeds from warrant exercise - 4,500
Costs incurred in connection with financing arrangements (6,500) (4,652)
Preferred stock dividends paid (6,392) -
Distributions to unitholders of subsidiary (21,966) (14,465)
Other (72) 306
----------- --------
Net cash provided by (used in) financing activities (240,781) 228,378
----------- --------
Net decrease in cash and cash equivalents (58,362) (2,672)
Cash and cash equivalents, beginning of period 68,228 6,544
----------- --------
Cash and cash equivalents, end of period $ 9,866 $ 3,872
=========== ========
</TABLE>
See notes to consolidated financial statements.
5
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Note 1 -- Organization and Accounting Policies
The consolidated financial statements include the accounts of Plains Resources
Inc., our wholly owned subsidiaries and Plains All American Pipeline, L.P.
("PAA"), in which we have an approximate 54% ownership interest. Plains All
American Inc., one of our wholly owned subsidiaries, serves as PAA's sole
general partner. For financial statement purposes, the assets, liabilities and
results of operations of PAA are included in our consolidated financial
statements, with the public unitholders' interest reflected as a minority
interest.
The accompanying consolidated financial statements and related notes present
our consolidated financial position as of September 30, 2000 and December 31,
1999, the results of our operations for the three and nine months ended
September 30, 2000 and 1999, and cash flows for the nine months ended September
30, 2000 and 1999. The financial statements have been prepared in accordance
with the instructions to interim reporting as prescribed by the Securities and
Exchange Commission ("SEC"). For further information, refer to our Form 10-K for
the year ended December 31, 1999, filed with the SEC.
All adjustments, consisting only of normal recurring adjustments, that in the
opinion of management were necessary for a fair statement of the results for the
interim periods, have been reflected. All significant intercompany transactions
have been eliminated. The results for the three and nine months ended September
30, 2000 are not necessarily indicative of the final results to be expected for
the full year. Certain reclassifications have been made to prior periods to
conform to the current period presentation. We evaluate the capitalized costs of
our oil and natural gas properties on an ongoing basis and have utilized the
most recently available information to estimate our reserves at September 30,
2000, 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.
Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for
Derivative Instruments and Hedging Activities ("SFAS 133"). SFAS 133 was
subsequently amended (i) in June 1999 by SFAS No. 137, Accounting for Derivative
Instruments and Hedging Activities - Deferral of the effective date of FASB
Statement No. 133 ("SFAS 137"), which deferred the effective date of SFAS 133 to
fiscal years beginning after June 15, 2000; and (ii) in June 2000 by SFAS 138,
"Accounting for Certain Derivative Instruments and Certain Hedge Activities,"
which amended certain provisions, inclusive of the definition of the normal
purchase and sale exclusion.
SFAS 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 so,
the type of hedge transaction. For fair value hedge transactions in which we are
hedging changes in the fair value of an asset, liability, or firm commitment,
changes in the fair value of the derivative instrument will generally be offset
in the income statement by changes in the fair value of the hedged item. For
cash flow hedge transactions, in which we are 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 ineffective portion of all hedges will be recognized in
earnings in the current period.
We will adopt SFAS 133, as amended, effective January 1, 2001. We believe we
have identified all instruments currently in place that will be subject to the
requirements of SFAS 133, however, due to the complex nature of SFAS 133 and
various interpretations regarding applications of SFAS 133 to certain
instruments, we have not fully determined what impact the adoption of SFAS 133
would have on the consolidated balance sheets, statements of operations and cash
flows. The FASB has formed a derivative implementation group which is addressing
assessment and implementation matters regarding the application of SFAS 133 for
consideration by the FASB. Adoption of this standard could increase volatility
in earnings and retained earnings (deficit) through comprehensive income.
6
<PAGE>
NOTE 2 -- INVENTORY AND OTHER ASSETS
Inventory consists of the following (in thousands):
September 30, December 31,
2000 1999
------------- ------------
Crude oil $ 24,164 $ 35,664
Materials and supplies 5,384 4,814
-------- --------
$ 29,548 $ 40,478
======== ========
Other assets consist of the following (in thousands):
September 30, December 31,
2000 1999
--------------- --------------
Pipeline linefill $ 31,030 $ 17,633
Deferred tax asset 47,745 67,366
Land 8,853 8,853
Debt issue costs, net 12,000 26,530
Other, net 2,551 9,385
-------- --------
$102,179 $129,767
======== ========
NOTE 3 -- UNAUTHORIZED TRADING LOSSES AND RESTATED FINANCIAL STATEMENTS
In November 1999, we discovered that a former employee of PAA had engaged in
unauthorized trading activity, resulting in losses of approximately $162.0
million ($174.0 million, including estimated associated costs and legal expenses
at December 31, 1999). A full investigation into the unauthorized trading
activities by outside legal counsel and independent accountants and consultants
determined that the vast majority of the losses occurred primarily from March
through November 1999, and that the impact warranted a restatement of previously
reported financial information for 1999 and 1998. Because the financial
statements of PAA are consolidated with our financial statements, adverse
effects on the financial statements of PAA directly affect our consolidated
financial statements. Consequently, the consolidated financial statements for
1999 appearing in this report were previously restated to reflect the
unauthorized trading losses. During the third quarter of 2000, we recognized an
additional $6.6 million charge for litigation related to the unauthorized
trading losses (See Note 11).
NOTE 4 -- ASSET DISPOSITIONS
We initiated the sale of approximately 5.2 million barrels of crude oil
linefill from the All American Pipeline in November 1999. This sale was
completed in March 2000. The linefill was located in the segment of the All
American Pipeline that extends from Emidio, California, to McCamey, Texas.
Except for minor third party volumes, Plains Marketing L.P., one of PAA's
subsidiaries, has been the sole shipper on this segment of the pipeline since
its predecessor acquired the line from Goodyear in July 1998. Proceeds from the
sale of the linefill were approximately $100.0 million, net of associated costs,
and were used (1) to repay outstanding indebtedness under PAA's $65.0 million
senior secured term credit facility entered into in December 1999 to fund short-
term working capital requirements resulting from the unauthorized trading losses
and (2) for general working capital purposes. We recognized a total gain of
$44.6 million, of which $16.5 million was recorded in the fourth quarter of
1999. The amount of crude oil linefill for sale at December 31, 1999 was $37.9
million and is included in assets held for sale on the consolidated balance
sheet at such date.
On March 24, 2000, we completed the sale of the above referenced segment of
the All American Pipeline to a unit of El Paso Energy Corporation for proceeds
of approximately $124.0 million, which are net of associated transaction costs
and estimated costs to remove certain equipment. We recognized a gain of
approximately $20.1 million in connection with the sale in the first quarter of
2000. Proceeds from the sale were used to permanently reduce the All American
Pipeline, L.P. term loan facility (see Note 6). The cost of the pipeline segment
is included in assets held for sale on the consolidated balance sheet at
December 31, 1999.
7
<PAGE>
NOTE 5 -- DEBT
On May 8, 2000, PAA entered into new bank credit agreements. The borrower
under the new facilities is Plains Marketing, L.P. PAA is a guarantor of the
obligations under the credit facilities. The obligations are also guaranteed by
the subsidiaries of Plains Marketing, L.P. PAA entered into the credit
agreements in order to:
. refinance the existing bank debt of Plains Marketing, L.P. and Plains
Scurlock Permian, L.P. in conjunction with the merger of Plains Scurlock
Permian, L.P. into All American Pipeline, L.P.;
. refinance existing bank debt of All American Pipeline, L.P.;
. repay us $114.0 million plus accrued interest of subordinated debt, and
. provide additional flexibility for working capital, capital expenditures, and
for other general corporate purposes.
PAA's new bank credit agreements consist of:
. a $400.0 million senior secured revolving credit facility. The revolving
credit facility is secured by substantially all of PAA's assets and matures
in April 2004. No principal is scheduled for payment prior to maturity. The
revolving credit facility bears interest at PAA's option at either the base
rate, as defined, plus an applicable margin, or LIBOR plus an applicable
margin. PAA incurs a commitment fee on the unused portion of the revolving
credit facility. At September 30, 2000, $292.0 million was outstanding on the
revolving credit facility.
. A $300.0 million senior secured letter of credit and borrowing facility, the
purpose of which is to provide standby letters of credit to support the
purchase and exchange of crude oil for resale and borrowings to finance crude
oil inventory that has been hedged against future price risk. The letter of
credit facility is secured by substantially all of PAA's assets and has a
sublimit for cash borrowings of $100.0 million to purchase crude oil that has
been hedged against future price risk. The letter of credit facility expires
in April 2003. 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 of PAA's current assets and current
liabilities (primarily inventory and accounts receivable and accounts payable
related to the purchase and sale of crude oil). At September 30, 2000,
approximately $79.5 million in letters of credit were outstanding under the
letter of credit and borrowing facility.
PAA's bank credit agreements prohibit distributions on, or purchases or
redemptions of, units if any default or event of default is continuing. In
addition, the agreements contain various covenants limiting PAA's ability to,
among other things:
. incur indebtedness;
. grant liens;
. sell assets;
. make investments;
. engage in transactions with affiliates;
. enter into prohibited contracts; and
. enter into a merger or consolidation.
PAA's bank credit agreements treat a change of control as an event of default
and also require PAA to maintain:
. a current ratio (as defined) of 1.0 to 1.0;
. a debt coverage ratio that is not greater that 4.0 to 1.0 for the period from
March 31, 2000 to March 31, 2002 and subsequently 3.75 to 1.0;
. an interest coverage ratio that is not less than 2.75 to 1.0; and
. a debt to capital ratio of not greater than 0.65 to 1.0.
At September 30, 2000, the carrying value of all variable rate bank debt of
$305.0 million approximated the fair value and liquidation value at that date.
The carrying value and fair value of the fixed rate debt was $277.0 million and
$282.1 million, respectively, at that date. The carrying value and estimated
fair value of redeemable preferred stock were $137.7 million and $198.3 million,
respectively, at September 30, 2000. At December 31, 1999, the carrying value of
all variable rate bank debt and the redeemable preferred stock of $506.1 million
and $138.8 million, respectively, approximated the fair value and liquidation
value at that date. The carrying value and fair value of the fixed rate debt was
$277.5 million and $270.7 million, respectively, at that date. The fair value of
fixed rate debt was based on quoted market prices based on trades of our
subordinated debt.
8
<PAGE>
Interest rate swaps and collars are used to hedge underlying debt obligations.
These instruments hedge specific debt issuances and qualify for hedge
accounting. The interest rate differential is reflected as an adjustment to
interest expense over the life of the instruments. At September 30, 2000, we had
interest rate swap and collar arrangements for an aggregate notional principal
amount of $240.0 million, which positions had an aggregate value of
approximately $0.6 million as of such date. These instruments are based on LIBOR
and generally provide for a floor of 5% and a ceiling of 6.5% for $90.0
million of debt, a floor of 6% and a ceiling of 8% for $125.0 million of debt
and 5.7% for $25.0 million of debt.
NOTE 6 -- EXTRAORDINARY ITEM
During the nine months ended September 30, 2000, we recognized extraordinary
losses consisting primarily of unamortized debt issue costs, of $5.0 million
(net of minority interest of $7.0 million and deferred tax of $3.2 million)
related to PAA's early extinguishment of debt and refinancing of its credit
agreements (see Notes 4 and 5).
Note 7 -- Treasury Stock
At September 30, 2000 and December 31, 1999, we had 46,600 shares of Series D
Cumulative Convertible Preferred Stock, $1.00 par value, authorized, issued and
outstanding. At September 30, 2000 and December 31, 1999, we had 50,000,000
shares of common stock, $0.10 par value, authorized. At September 30, 2000 and
December 31, 1999, 18,139,727 shares and 17,924,050 shares, respectively, were
issued and 17,880,827 shares and 17,924,050 shares, respectively, were
outstanding.
In June 2000, our Board of Directors authorized the repurchase of up to one
million shares of our common stock. As of September 30, 2000, we had repurchased
258,900 common shares at a cost of $4.2 million. In October 2000, we repurchased
an additional 606,000 common shares for approximately $11.5 million. On November
9, 2000, our Board authorized the repurchase of an additional one million
shares.
NOTE 8 -- EARNINGS PER SHARE
The following is a reconciliation of the numerators and the denominators of
the basic and diluted earnings (loss) per share computations for income (loss)
from continuing operations before extraordinary items for the three and nine
months ended September 30, 2000 and 1999 (in thousands, except per share
amounts):
<TABLE>
<CAPTION>
For the Three Months Ended September 30,
---------------------------------------------------------------------------
2000 1999 (restated)
----------------------------------- -------------------------------------
Income Shares Per Income Shares Per
(Numera- (Denomi- Share (Numera- (Denomi- Share
tor) nator) Amount tor) nator) Amount
---------- ---------- --------- ---------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C>
Net income (loss) before extraordinary item $ 6,734 $(20,047)
Less: preferred stock dividends (3,694) (2,493)
-------- --------
Income (loss) available to common stockholders 3,040 17,970 $ 0.17 (22,540) 17,311 $ (1.30)
====== =======
Effect of dilutive securities:
Convertible preferred stock - - - -
Employee stock options and warrants - 968 - -
-------- ------ -------- ------
Income (loss) available to common
stockholders assuming dilution $ 3,040 18,938 $ 0.16 $(22,540) 17,311 $ (1.30)
======== ====== ====== ======== ====== =======
For the Nine Months Ended September 30,
---------------------------------------------------------------------------
2000 1999 (restated)
----------------------------------- -------------------------------------
Income Shares Per Income Shares Per
(Numera- (Denomi- Share (Numera- (Denomi- Share
tor) nator) Amount tor) nator) Amount
---------- ---------- --------- ---------- ---------- -----------
Net income (loss) before extraordinary item $ 37,282 $(28,324)
Less: preferred stock dividends (11,106) (7,327)
-------- --------
Income (loss) available to common stockholders 26,176 17,963 $ 1.46 (35,651) 17,040 $ (2.09)
====== =======
Effect of dilutive securities:
Convertible preferred stock 11,106 10,862 - -
Employee stock options and warrants - 800 - -
-------- ------ -------- ------
Income (loss) available to common
stockholders assuming dilution $ 37,282 29,625 $ 1.26 $(35,651) 17,040 $ (2.09)
======== ====== ====== ======== ====== =======
</TABLE>
9
<PAGE>
NOTE 9 -- OPERATING SEGMENTS
Our 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 pipeline transportation, purchases and resales of crude oil at various points
along the distribution chain and the leasing of certain terminalling and storage
facilities. We evaluate performance based on gross margin, gross profit and
income (loss) before income taxes, minority interest and extraordinary items.
<TABLE>
<CAPTION>
(in thousands) (unaudited) Upstream Midstream Total
-------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
For the Three Months Ended September 30, 2000
Revenues:
External Customers $ 38,610 $ 703,944 $ 742,554
Intersegment (a) - 52,982 52,982
Other income (expense) 372 317 689
-------- ---------- ----------
Total revenues of reportable segments $ 38,982 $ 757,243 $ 796,225
======== ========== ==========
Segment gross margin (b) $ 22,676 $ 25,553 $ 48,229
Segment gross profit (c) 20,624 17,773 38,397
Segment income before income taxes,
minority interest and extraordinary item 9,068 4,017 13,085
-------------------------------------------------------------------------------------------------------------
For the Three Months Ended September 30, 1999 (restated)
Revenues:
External Customers $ 34,654 $1,098,506 $1,133,160
Intersegment (a) - 29,302 29,302
Other income (expense) 29 330 359
-------- ---------- ----------
Total revenues of reportable segments $ 34,683 $1,128,138 $1,162,821
======== ========== ==========
Segment gross margin (b) $ 18,328 $ (40,311) $ (21,983)
Segment gross profit (c) 16,777 (47,658) (30,881)
Segment income (loss) before income taxes
and minority interest 4,900 (60,628) (55,728)
-------------------------------------------------------------------------------------------------------------
For the Nine Months Ended September 30, 2000
Revenues:
External Customers $109,192 $2,347,826 $2,457,018
Intersegment (a) - 147,386 147,386
Gain on sale of assets - 48,188 48,188
Other income (expense) (3,633) 10,911 7,278
-------- ---------- ----------
Total revenues of reportable segments $105,559 $2,554,311 $2,659,870
======== ========== ==========
Segment gross margin (b) $ 62,580 $ 94,063 $ 156,643
Segment gross profit (c) 55,579 69,768 125,347
Segment income before income taxes,
minority interest and extraordinary item 15,872 84,696 100,568
-------------------------------------------------------------------------------------------------------------
For the Nine Months Ended September 30, 1999 (restated)
Revenues:
External Customers $ 80,985 $2,416,116 $2,497,101
Intersegment (a) - 29,976 29,976
Other income (expense) 48 618 666
-------- ---------- ----------
Total revenues of reportable segments $ 81,033 $2,446,710 $2,527,743
======== ========== ==========
Segment gross margin (b) $ 40,996 $ (37,682) $ 3,314
Segment gross profit (c) 35,962 (53,263) (17,301)
Segment income (loss) before income taxes and
minority interest 3,726 (80,529) (76,803)
-------------------------------------------------------------------------------------------------------------
</TABLE>
a) Intersegment sales were conducted on an arm's length basis.
b) Gross margin is calculated as revenues less cost of sales and operations.
c) Gross profit is calculated as revenues less costs of sales and operations
and general and administrative expenses.
10
<PAGE>
NOTE 10 -- PREFERRED STOCK DIVIDENDS
On April 1, 2000, we paid cash dividends of approximately $6.0 million on our
Series D, F and G preferred stock. The dividends on the Series D preferred stock
are for the period from January 1, 2000 through March 31, 2000. The Series F
preferred stock was issued on December 15, 1999 and such dividend covers the
period from that date through March 31, 2000. The dividends on the Series G
preferred stock are for the period from October 1, 1999 through March 31, 2000.
On July 19, 2000, we paid cash dividends of approximately $0.3 million on our
Series D preferred stock covering the period from April 1, 2000 through June 30,
2000.
On October 1, 2000, we paid cash dividends of approximately $7.0 million on
our Series D, F and G preferred stock. The dividends on the Series D preferred
stock are for the period from July 1, 2000 through September 30, 2000. The
dividends on the Series F and G preferred stock are for the period from April 1,
2000 through September 30, 2000.
NOTE 11 -- CONTINGENCIES
Texas Securities Litigation. On November 29, 1999, a class action lawsuit was
filed in the United States District Court for the Southern District of Texas
entitled Di Giacomo v. Plains All American Pipeline, L.P. ("PAA"), et al. The
suit alleged that PAA and certain of its general partner's officers and
directors violated federal securities laws, primarily in connection with
unauthorized trading by a former employee. An additional nineteen cases have
been filed in the Southern District of Texas, some of which name the general
partner and us as additional defendants. All of the federal securities claims
are being consolidated into two actions. The first consolidated action is that
filed by purchasers of our common stock and options, and is captioned Koplovitz
v. Plains Resources Inc., et al. The second consolidated action is that filed by
purchasers of PAA's common units, and is captioned Di Giacomo v. Plains All
American Pipeline, L.P., et al. Plaintiffs alleged that the defendants were
liable for securities fraud violations under Rule 10b-5 and Section 20(a) of the
Securities Exchange Act of 1934 and for making false registration statements
under Sections 11 and 15 of the Securities Act of 1933.
We and PAA have reached an agreement in principle with representatives for the
plaintiffs for the settlement of all of the federal securities actions.
Aggregate amounts to be paid under the agreement in principle total
approximately $29.5 million plus interest from October 1, 2000 through the date
actual proceeds are remitted to representatives for the plaintiffs. Our
insurance carrier has deposited $15.0 million to an escrow account to fund
amounts payable under our insurance policies. The Boards of Directors of PAA and
Plains Resources have formed special independent committees to review and
approve final allocation of the settlement costs between PAA and us. Based on an
estimate of such allocation, which allocation is currently under review by the
committees, in the third quarter of 2000 we accrued an additional $6.6 million
of litigation costs and related expenses, which reduced basic earnings per
common share after minority interest and taxes for the three and nine months
ended September 30, 2000 by $0.12 ($0.11 diluted) and $0.12 ($0.07 diluted),
respectively.
The settlement is subject to a number of conditions, including negotiation and
finalization of a stipulation and agreement of settlement and related
documentation, and approval of the United States District Court for the Southern
District of Texas. The agreement in principle does not affect the Texas
Derivative Litigation and Delaware Derivative Litigation described below.
Texas Derivative Litigation. On July 11, 2000, a derivative lawsuit was filed
in the United States District Court for the Southern District of Texas entitled
Fernandez v. Plains All American Inc., et al., naming the general partner, its
directors and certain of its officers as defendants. This lawsuit contains the
same claims and seeks the same relief as the Delaware derivative litigation
described below. A motion to dismiss was filed on behalf of the defendants on
August 14, 2000.
Delaware Derivative Litigation. On December 3, 1999, two derivative lawsuits
were filed in the Delaware Chancery Court, New Castle County, entitled Susser v.
Plains All American Inc., et al and Senderowitz v. Plains All American Inc., et
al. These suits, and three others which were filed in Delaware subsequently,
named the general partner, its directors and certain of its officers as
defendants, and allege that the defendants breached the fiduciary duties that
they owed to PAA and its unitholders by failing to monitor properly the
activities of its employees. The court has consolidated all of the cases under
the caption In Re Plains All American Inc. Shareholders Litigation, and has
designated the complaint filed in Sussex v. Plains All American Inc. as the
operative complaint in the consolidated action. A motion to dismiss was filed on
behalf of the defendants on August 11, 2000.
11
<PAGE>
The plaintiffs in the Delaware securities litigation seek that the defendants
(1) account for all losses and damages allegedly sustained by Plains All
American from the unauthorized trading losses, (2) establish and maintain
effective internal controls ensuring that PAA's affiliates and persons
responsible for its affairs do not engage in wrongful practices detrimental to
Plains All American, (3) account for the plaintiffs' costs and expenses in
litigation, including reasonable attorneys' fees, accountants' fees, and
experts' fees and (4) provide the plaintiffs any additional relief as may be
just and proper under the circumstances.
We intend to vigorously defend the claims made against us in the Texas
derivative litigation and the Delaware derivative litigation. However, there can
be no assurance that we will be successful in our defense or that these lawsuits
will not have a material adverse effect on our financial position, results of
operations or cash flows.
On July 9, 1987, Exxon Corporation ("Exxon") filed an interpleader action in
the United States District Court for the Middle District of Florida, Exxon
Corporation v. E. W. Adams, et al., Case Number 87-976-CIV-T-23-B. This action
was filed by Exxon to interplead royalty funds as a result of a title
controversy between certain mineral owners in a field in Florida. One group of
mineral owners, John W. Hughes, et al. (the "Hughes Group"), filed a
counterclaim against Exxon alleging fraud, conspiracy, conversion of funds,
declaratory relief, federal and Florida RICO, breach of contract and accounting,
as well as challenging the validity of certain oil and natural gas leases owned
by Exxon, and seeking exemplary and treble damages. In March 1993, but effective
November 1, 1992, Calumet Florida Inc. ("Calumet"), our wholly owned subsidiary,
acquired all of Exxon's leases in the field affected by this lawsuit. In order
to address those counterclaims challenging the validity of certain oil and
natural gas leases, which constitute approximately 10% of the land underlying
this unitized field, Calumet filed a motion to join Exxon as plaintiff in the
subject lawsuit, which was granted July 29, 1994. In August 1994, the Hughes
Group amended its counterclaim to add Calumet as a counter-defendant. Exxon and
Calumet filed a motion to dismiss the counterclaims. On March 22, 1996, the
Court granted Exxon's and Calumet's motion to dismiss the counterclaims alleging
fraud, conspiracy, and federal and Florida RICO violations and challenging the
validity of certain of our oil and natural gas leases but denied such motion as
to the counterclaim alleging conversion of funds. Effective January 1, 2000,
Calumet settled all of the Hughes claims against Calumet with a payment to the
Hughes group of the total sum of $100,000. The remaining defendants filed a writ
seeking to stay the trial but no relief was granted prior to the trial date.
Trial was held on June 19, 2000. By final judgment dated August 18, 2000, the
court dismissed all claims by the Hughes group and the remaining defendants
against Calumet. The remaining defendants have appealed the judgment.
We, in the ordinary course of business, are a claimant and/or a defendant in
various other legal proceedings. Management does not believe that the outcome of
these other legal proceedings, individually and in the aggregate, will have a
materially adverse effect on our financial condition, results of operations or
cash flows.
Derivatives. We utilize derivative financial instruments to hedge our exposure
to price volatility on crude oil. We have entered into various arrangements to
fix the NYMEX crude oil spot price for a significant portion of our crude oil
production. For the fourth quarter of 2000, we have entered into various
arrangements which provide for us to receive an average minimum NYMEX WTI price
of $16.25 per barrel on 18,500 barrels of oil per day. Approximately 10,000
barrels per day of these volumes will participate in price increases up to
$19.75 per barrel. For 2001, we have entered into various arrangements, using a
combination of swaps, collars and purchased puts and calls, which will provide
for us to receive an average minimum NYMEX price of approximately $22.75 per
barrel on 20,500 barrels per day with almost full market price participation
up to an average of $27.00 per barrel. For 2002, we have entered into various
arrangements that provide for us to receive an average minimum NYMEX WTI price
of $23.00 per barrel on 10,000 barrels per day with full market price
participation up to an average of $24.90 per barrel. Location and quality
differentials attributable to our properties are not included in the foregoing
prices. The agreements provide for monthly settlement based on the differential
between the agreement price and the actual NYMEX crude oil price. Gains or
losses are recognized in the month of related production and are included in
crude oil and natural gas sales. Such contracts resulted in a reduction in
revenues of $22.2 million and $56.7 million in the third quarter and first nine
months of 2000, respectively. The unrealized loss at September 30, 2000, with
respect to such contracts was $24.0 million.
At September 30, 2000, our hedging activities included crude oil futures
contracts maturing through 2001, covering approximately 6.9 million barrels of
crude oil. Since such contracts are designated as hedges and correlate to price
movements of crude oil, any gains or losses resulting from market changes will
be largely offset by losses or gains on our hedged inventory or anticipated
purchases of crude oil. Such contracts resulted in a reduction in revenues of
$1.2 million in the third quarter of 2000 and an increase in revenues of $0.1
million in the nine months ended September 30, 2000. The unrealized loss at
September 30, 2000, with respect to such contracts was $7.0 million.
12
<PAGE>
NOTE 12 -- CONSOLIDATING FINANCIAL STATEMENTS
The following financial information presents consolidating financial
statements which include:
. the parent company only ("Parent");
. the guarantor subsidiaries on a combined basis ("Guarantor Subsidiaries");
. the nonguarantor subsidiaries on a combined basis ("Nonguarantor
Subsidiaries");
. elimination entries necessary to consolidate the Parent, the Guarantor
Subsidiaries and the Nonguarantor Subsidiaries; and
. Plains Resources Inc. on a consolidated basis.
These statements are presented because our Series A-E subordinated notes are
not guaranteed by PAA and our consolidated financial statements include the
accounts of PAA.
13
<PAGE>
PLAINS RESOURCES RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET (UNAUDITED) (IN THOUSANDS)
SEPTEMBER 30, 2000
<TABLE>
<CAPTION>
GUARANTOR NONGUARANTOR INTERCOMPANY
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
---------- ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 5,168 $ 388 $ 4,310 $ - $ 9,866
Accounts receivable and other 17,576 11,050 382,913 - 411,539
Inventory - 7,261 22,287 - 29,548
--------- --------- -------- --------- ----------
Total current assets 22,744 18,699 409,510 - 450,953
--------- --------- -------- --------- ----------
PROPERTY AND EQUIPMENT 237,087 543,203 468,333 - 1,248,623
Less allowance for depreciation,
depletion and amortization (217,335) (133,268) (23,885) (55,386) (429,874)
--------- --------- -------- --------- ----------
19,752 409,935 444,448 (55,386) 818,749
--------- --------- -------- --------- ----------
INVESTMENTS IN SUBSIDIARIES AND
INTERCOMPANY ADVANCES 317,690 (222,305) (28,327) (67,058) -
OTHER ASSETS 40,042 3,758 58,379 - 102,179
--------- --------- -------- --------- ----------
$ 400,228 $ 210,087 $884,010 $(122,444) $1,371,881
========= ========= ======== ========= ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and other current liabilities $ 26,754 $ 42,953 $349,034 $ (22) $ 418,719
Notes payable and other current obligations - 511 - - 511
--------- --------- -------- --------- ----------
Total current liabilities 26,754 43,464 349,034 (22) 419,230
BANK DEBT 13,000 - - - 13,000
BANK DEBT OF A SUBSIDIARY - - 292,000 - 292,000
SUBORDINATED DEBT 277,639 - - - 277,639
OTHER LONG-TERM DEBT - 1,533 - - 1,533
OTHER LONG-TERM LIABILITIES 2,140 - 1,600 - 3,740
--------- --------- -------- --------- ----------
319,533 44,997 642,634 (22) 1,007,142
--------- --------- -------- --------- ----------
MINORITY INTEREST (70,037) - 236,600 92 166,655
--------- --------- -------- --------- ----------
CUMULATIVE CONVERTIBLE
PREFERRED STOCK, STATED
AT LIQUIDATION PREFERENCE 137,721 - - - 137,721
--------- --------- -------- --------- ----------
NON-REDEEMABLE PREFERRED STOCK,
COMMON STOCK AND
OTHER STOCKHOLDERS' EQUITY
Series D Cumulative Convertible Preferred Stock 23,300 - - - 23,300
Common Stock 1,814 78 - (78) 1,814
Additional paid-in capital 132,782 3,951 45,530 (49,481) 132,782
Retained earnings (accumulated deficit) (140,664) 161,061 (40,754) (72,955) (93,312)
Treasury stock, at cost (4,221) - - - (4,221)
--------- --------- -------- --------- ----------
13,011 165,090 4,776 (122,514) 60,363
--------- --------- -------- --------- ----------
$ 400,228 $ 210,087 $884,010 $(122,444) $1,371,881
========= ========= ======== ========= ==========
</TABLE>
14
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET (IN THOUSANDS)
DECEMBER 31, 1999
<TABLE>
<CAPTION>
GUARANTOR NONGUARANTOR INTERCOMPANY
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
---------- ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 9,241 $ 5,134 $ 53,853 $ - $ 68,228
Accounts receivable and other 1,808 11,221 508,919 - 521,948
Inventory - 5,652 34,826 - 40,478
Assets held for sale - - 141,486 - 141,486
--------- --------- ---------- --------- ----------
Total current assets 11,049 22,007 739,084 - 772,140
--------- --------- ---------- --------- ----------
PROPERTY AND EQUIPMENT 235,158 494,279 460,730 - 1,190,167
Less allowance for depreciation,
depletion and amortization (215,463) (120,016) (11,649) (55,386) (402,514)
--------- --------- ---------- --------- ----------
19,695 374,263 449,081 (55,386) 787,653
--------- --------- ---------- --------- ----------
INVESTMENTS IN SUBSIDIARIES AND
INTERCOMPANY ADVANCES 440,115 (224,598) (45,683) (169,834) -
OTHER ASSETS 40,337 14,752 74,678 - 129,767
--------- --------- ---------- --------- ----------
$ 511,196 $ 186,424 $1,217,160 $(225,220) $1,689,560
========= ========= ========== ========= ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and other current liabilities $ 23,700 $ 35,457 $ 487,212 $ 24 $ 546,393
Notes payable and other current obligations - 511 109,369 - 109,880
--------- --------- ---------- --------- ----------
Total current liabilities 23,700 35,968 596,581 24 656,273
BANK DEBT 137,300 - - - 137,300
BANK DEBT OF A SUBSIDIARY - - 259,450 - 259,450
SUBORDINATED DEBT 277,909 - 105,000 (105,000) 277,909
OTHER LONG-TERM DEBT - 2,044 - - 2,044
OTHER LONG-TERM LIABILITIES 1,954 - 19,153 - 21,107
--------- --------- ---------- --------- ----------
440,863 38,012 980,184 (104,976) 1,354,083
--------- --------- ---------- --------- ----------
MINORITY INTEREST (70,037) - 226,082 - 156,045
--------- --------- ---------- --------- ----------
CUMULATIVE CONVERTIBLE
PREFERRED STOCK, STATED
AT LIQUIDATION PREFERENCE 138,813 - - - 138,813
--------- --------- ---------- --------- ----------
NON-REDEEMABLE PREFERRED STOCK,
COMMON STOCK AND
OTHER STOCKHOLDERS' EQUITY
Series D Cumulative Convertible Preferred Stock 23,300 - - - 23,300
Common Stock 1,792 78 - (78) 1,792
Additional paid-in capital 130,027 3,952 43,261 (47,213) 130,027
Retained earnings (accumulated deficit) (153,562) 144,382 (32,367) (72,953) (114,500)
--------- --------- ---------- --------- ----------
1,557 148,412 10,894 (120,244) 40,619
--------- --------- ---------- --------- ----------
$ 511,196 $ 186,424 $1,217,160 $(225,220) $1,689,560
========= ========= ========== ========= ==========
</TABLE>
15
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED) (IN THOUSANDS)
THREE MONTHS ENDED SEPTEMBER 30, 2000
<TABLE>
<CAPTION>
GUARANTOR NONGUARANTOR INTERCOMPANY
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
---------- ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
REVENUES
Oil and natural gas sales $ 5 $38,198 $ - $ 407 $ 38,610
Marketing, transportation, storage and terminalling - - 756,926 (52,982) 703,944
Gain on sale of assets - - - - -
Interest and other income 277 95 317 - 689
--------- --------- --------- -------- --------
282 38,293 757,243 (52,575) 743,243
--------- --------- --------- -------- --------
EXPENSES
Production expenses - 15,934 - - 15,934
Marketing, transportation, storage and terminalling - - 724,366 (52,575) 671,791
Unauthorized trading losses and related expenses - - 6,600 - 6,600
General and administrative 814 1,238 7,780 - 9,832
Noncash compensation expense - - 2,138 - 2,138
Depreciation, depletion and amortization 813 4,498 5,457 - 10,768
Interest expense 1,413 5,204 6,478 - 13,095
--------- --------- --------- -------- --------
3,040 26,874 752,819 (52,575) 730,158
--------- --------- --------- -------- --------
Income (loss) before income taxes,
minority interest and extraordinary item (2,758) 11,419 4,424 - 13,085
Minority interest - - 2,047 - 2,047
--------- --------- --------- -------- --------
Income (loss) before income taxes (2,758) 11,419 2,377 - 11,038
Income tax expense (benefit):
Current (55) 228 47 - 220
Deferred (1,020) 4,225 879 - 4,084
--------- --------- --------- -------- --------
Income (loss) before extraordinary item (1,683) 6,966 1,451 - 6,734
Extraordinary item, net of tax benefit
and minority interest - - - - -
--------- --------- --------- -------- --------
NET INCOME (LOSS) (1,683) 6,966 1,451 - 6,734
Less: cumulative preferred stock dividends 3,694 - - - 3,694
--------- --------- --------- -------- --------
NET INCOME (LOSS) AVAILABLE
TO COMMON STOCKHOLDERS $(5,377) $ 6,966 $ 1,451 $ - $ 3,040
========= ========= ========= ======== ========
</TABLE>
16
<PAGE>
PLAINS RESOURCES RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED) (IN THOUSANDS) (RESTATED)
THREE MONTHS ENDED SEPTEMBER 30, 1999
<TABLE>
<CAPTION>
GUARANTOR NONGUARANTOR INTERCOMPANY
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
---------- ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
REVENUES
Oil and natural gas sales $ - $34,266 $ - $ 388 $ 34,654
Marketing, transportation, storage and terminalling - - 1,127,808 (29,302) 1,098,506
Interest and other income 17 12 330 - 359
--------- ------- ---------- -------- ----------
17 34,278 1,128,138 (28,914) 1,133,519
--------- ------- ---------- -------- ----------
EXPENSES
Production expenses - 16,326 - - 16,326
Marketing, transportation, storage and terminalling - - 1,095,481 (28,914) 1,066,567
Unauthorized trading losses and related expenses - - 72,250 - 72,250
General and administrative 338 1,213 7,347 - 8,898
Noncash compensation expense - - 1,947 - 1,947
Depreciation, depletion and amortization 538 4,835 4,735 - 10,108
Interest expense 2,194 4,338 6,619 - 13,151
--------- ------- ---------- -------- ----------
3,070 26,712 1,188,379 (28,914) 1,189,247
--------- ------- ---------- -------- ----------
Income (loss) before income taxes and minority
interest (3,053) 7,566 (60,241) - (55,728)
Minority interest - - (23,786) - (23,786)
--------- ------- ---------- -------- ----------
Income (loss) before income taxes (3,053) 7,566 (36,455) - (31,942)
Income tax expense (benefit)
Current (5,049) - 5,049 - -
Deferred 6,232 (50) (18,077) - (11,895)
--------- ------- ---------- -------- ----------
NET INCOME (LOSS) (4,236) 7,616 (23,427) - (20,047)
Less: cumulative preferred stock dividends 2,493 - - - 2,493
--------- ------- ---------- -------- ----------
NET INCOME (LOSS) AVAILABLE
TO COMMON STOCKHOLDERS $(6,729) $ 7,616 $ (23,427) $ - $ (22,540)
========= ======= ========== ======== ==========
</TABLE>
17
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED) (IN THOUSANDS)
NINE MONTHS ENDED SEPTEMBER 30, 2000
<TABLE>
<CAPTION>
GUARANTOR NONGUARANTOR INTERCOMPANY
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
---------- ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
REVENUES
Oil and natural gas sales $ 5 $107,964 $ - $ 1,223 $ 109,192
Marketing, transportation, storage and terminalling - - 2,495,212 (147,386) 2,347,826
Gain on sale of assets - - 48,188 - 48,188
Interest and other income (expense) (767) 196 10,911 (3,062) 7,278
--------- ------- ---------- --------- ----------
(762) 108,160 2,554,311 (149,225) 2,512,484
--------- ------- ---------- --------- ----------
EXPENSES
Production expenses - 46,612 - - 46,612
Marketing, transportation, storage and terminalling - - 2,393,326 (146,163) 2,247,163
Unauthorized trading losses and related expenses - - 6,600 - 6,600
General and administrative 1,876 5,125 24,295 - 31,296
Noncash compensation expense - - 2,269 - 2,269
Depreciation, depletion and amortization 2,488 13,252 20,324 - 36,064
Interest expense 7,568 15,828 21,578 (3,062) 41,912
--------- ------- ---------- --------- ----------
11,932 80,817 2,468,392 (149,225) 2,411,916
--------- ------- ---------- --------- ----------
Income (loss) before income taxes,
minority interest and extraordinary item (12,694) 27,343 85,919 - 100,568
Minority interest - - 39,451 - 39,451
--------- ------- ---------- --------- ----------
Income (loss) before income taxes (12,694) 27,343 46,468 - 61,117
Income tax expense (benefit):
Current (203) 383 561 - 741
Deferred (5,465) 10,281 18,278 - 23,094
--------- ------- ---------- --------- ----------
Income (loss) before extraordinary item (7,026) 16,679 27,629 - 37,282
Extraordinary item, net of tax benefit
and minority interest - - (4,988) - (4,988)
--------- ------- ---------- --------- ----------
NET INCOME (LOSS) (7,026) 16,679 22,641 - 32,294
Less: cumulative preferred stock dividends 11,106 - - - 11,106
--------- ------- ---------- --------- ----------
NET INCOME (LOSS) AVAILABLE
TO COMMON STOCKHOLDERS $(18,132) $16,679 $ 22,641 $ - $ 21,188
========= ======= ========== ========= ==========
</TABLE>
18
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED) (IN THOUSANDS) (RESTATED)
NINE MONTHS ENDED SEPTEMBER 30, 1999
<TABLE>
<CAPTION>
GUARANTOR NONGUARANTOR INTERCOMPANY
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
---------- ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
REVENUES
Oil and natural gas sales $ - $79,923 $ - $ 1,062 $ 80,985
Marketing, transportation, storage and terminalling - - 2,484,063 (67,947) 2,416,116
Interest and other income (expense) 14 34 618 - 666
--------- ------- ---------- --------- ----------
14 79,957 2,484,681 (66,885) 2,497,767
--------- ------- ---------- --------- ----------
EXPENSES
Production expenses - 39,989 - - 39,989
Marketing, transportation, storage and terminalling - - 2,405,758 (66,885) 2,338,873
Unauthorized trading losses and related expenses - - 114,925 - 114,925
General and administrative 1,226 3,809 15,580 - 20,615
Noncash compensation expense - - 1,947 - 1,947
Depreciation, depletion and amortization 1,798 12,349 11,406 - 25,553
Interest expense 4,807 13,329 14,532 - 32,668
--------- ------- ---------- --------- ----------
7,831 69,476 2,564,148 (66,885) 2,574,570
--------- ------- ---------- --------- ----------
Income (loss) before income taxes and minority interest (7,817) 10,481 (79,467) - (76,803)
Minority interest - - (32,014) - (32,014)
--------- ------- ---------- --------- ----------
Income (loss) before income taxes (7,817) 10,481 (47,453) - (44,789)
Income tax expense (benefit)
Current (8,205) - 8,205 - -
Deferred 9,244 - (25,709) - (16,465)
--------- ------- ---------- --------- ----------
NET INCOME (LOSS) (8,856) 10,481 (29,949) - (28,324)
Less: cumulative preferred stock dividends 7,327 - - - 7,327
--------- ------- ---------- --------- ----------
NET INCOME (LOSS) AVAILABLE
TO COMMON STOCKHOLDERS $(16,183) $10,481 $ (29,949) $ - $ (35,651)
========= ======= ========== ========= ==========
</TABLE>
19
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (UNAUDITED) (IN THOUSANDS)
NINE MONTHS ENDED SEPTEMBER 30, 2000
<TABLE>
<CAPTION>
GUARANTOR NONGUARANTOR INTERCOMPANY
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
---------- ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income (loss) $ (7,026) $ 16,679 $ 22,641 $ - $ 32,294
Adjustments to reconcile net
income to net cash
provided by (used in)
operating activities:
Depreciation, depletion, and
amortization 2,488 13,252 20,324 - 36,064
Gain on sale of assets (Note 4] - - (48,188) - (48,188)
Minority interest in income
of a subsidiary - - 32,484 - 32,484
Deferred income tax (5,465) 10,281 15,088 - 19,904
Other noncash items 6,060 - 6,843 - 12,903
Change in assets and
liabilities resulting from
operating activities:
Accounts receivable and other (15,768) 168 95,284 - 79,684
Inventory - (1,609) 12,539 - 10,930
Pipeline linefill - - (13,397) - (13,397)
Accounts payable and other
current liabilities 3,054 3,193 (143,451) - (137,204)
Other long-term liabilities and
deferred credits - - (8,000) - (8,000)
---------- ------------ ------------ ------------ ------------
NET CASH FLOWS PROVIDED BY
(USED IN) OPERATING
ACTIVITIES (16,657) 41,964 (7,833) - 17,474
---------- ------------ ------------ ------------ ------------
CASH FLOWS FROM INVESTING
ACTIVITIES
Payments for crude oil
pipeline, gathering
and terminal assets - - (6,859) - (6,859)
Payments for acquisition,
exploration, and development costs (1,715) (48,135) - - (49,850)
Payments for additions to
other property and assets (213) (1,364) (628) - (2,205)
Proceeds from sale of assets
(Note 4) - - 223,859 - 223,859
---------- ------------ ------------ ------------ ------------
NET CASH PROVIDED BIN) INVESTING
ACTIVITIES (1,928) (49,499) 216,372 - 164,945
---------- ------------ ------------ ------------ ------------
CASH FLOWS FROM FINANCING
ACTIVITIES
Advances/investments with
affiliates 128,194 3,300 (131,494) - -
Proceeds from long-term debt 127,025 - 794,800 - 921,825
Proceeds from short-term debt - - 47,750 - 47,750
Principal payments of
long-term debt (251,325) (511) (812,900) - (1,064,736)
Principal payments of
short-term debt - - (106,469) - (106,469)
Purchase of treasury stock (4,221) - - - (4,221)
Costs incurred in connection
with financing arrangements - - (6,500) - (6,500)
Dividends paid (6,392) - - - (6,392)
Distribution to unitholders 21,303 - (43,269) - (21,966)
Other (72) - - - (72)
---------- ------------ ------------ ------------ ------------
NET CASH PROVIDED BY
(USED IN) FINANCING
ACTIVITIES 14,512 2,789 (258,082) - (240,781)
---------- ------------ ------------ ------------ ------------
Net decrease in cash and
cash equivalents (4,073) (4,746) (49,543) - (58,362)
Cash and cash equivalents,
beginning of period 9,241 5,134 53,853 - 68,228
---------- ------------ ------------ ------------ ------------
Cash and cash equivalents,
end of period $ 5,168 $ 388 $ 4,310 $ - $ 9,866
========== ============ ============ ============ ============
</TABLE>
20
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (UNAUDITED) (IN THOUSANDS)
(RESTATED)
NINE MONTHS ENDED SEPTEMBER 30, 1999
<TABLE>
<CAPTION>
GUARANTOR NONGUARANTOR INTERCOMPANY
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
---------- ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ (8,856) $ 10,481 $ (29,949) $ - $ (28,324)
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation, depletion, and amortization 1,798 12,349 11,406 - 25,553
Minority interest in income of a subsidiary - - (32,014) - (32,014)
Deferred income tax 9,244 - (25,709) - (16,465)
Other noncash items 1,216 (211) 2,163 - 3,168
Change in assets and liabilities
resulting from operating activities:
Accounts receivable and other (1,056) (3,340) (155,165) - (159,561)
Inventory - 216 (37,767) - (37,551)
Pipeline linefill - - (3) - (3)
Accounts payable and other current
liabilities 5,590 (12,852) 249,352 200 242,290
Other long-term liabilities and
deferred credits - - 10,873 - 10,873
---------- ------------ ----------- ------------ ----------
NET CASH FLOWS PROVIDED BY
(USED IN) OPERATING ACTIVITIES 7,936 6,643 (6,813) 200 7,966
---------- ------------ ----------- ------------ ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Payment for acquisition of midstream assets - - (173,070) - (173,070)
Payments for crude oil pipeline,
gathering and terminal assets - - (7,785) - (7,785)
Payments for acquisition, exploration,
and development costs (4,223) (53,469) - - (57,692)
Payments for additions to other
property and assets 140 (340) (269) - (469)
---------- ------------ ----------- ------------ ----------
NET CASH USED IN INVESTING ACTIVITIES (4,083) (53,809) (181,124) - (239,016)
---------- ------------ ----------- ------------ ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Advances/investments with affiliates (76,165) 47,395 28,770 - -
(Payment) proceeds from issuance of
Class B Common Units (25,000) - 25,000 - -
Proceeds from long-term debt 226,350 - 281,971 - 508,321
Proceeds from short-term debt - - 42,150 - 42,150
Principal payments of long-term debt (153,011) - (133,121) - (286,132)
Principal payments of short-term debt - - (21,650) - (21,650)
Proceeds from warrant exercise 4,500 - - - 4,500
Costs incurred in connection with
financing arrangements (1,125) - (3,527) (4,652)
Distribution to unitholders 20,154 - (34,619) - (14,465)
Other 306 - - - 306
---------- ------------ --------- ------- ---------
NET CASH PROVIDED BY (USED IN) FINANCING
ACTIVITIES (3,991) 47,395 184,974 - 228,378
---------- ------------ --------- --------- ---------
Net increase (decrease) in cash and
cash equivalents (138) 229 (2,963) 200 (2,672)
Cash and cash equivalents, beginning
of period 142 194 6,408 (200) 6,544
---------- ------------ -------- --------- ---------
Cash and cash equivalents, end of
period $ 4 423 $ 3,445 $ - $ 3,872
========== ============ ======== ========= =========
</TABLE>
21
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
General
We are an independent energy company engaged in two related lines of business
within the energy sector industry. Our first line of business, which we refer to
as "upstream," acquires, exploits, develops, explores and produces crude oil and
natural gas. Our second line of business, which we refer to as "midstream," is
engaged in the marketing, transportation and terminalling of crude oil. We
conduct this second line of business through our majority ownership in Plains
All American Pipeline, L.P. ("PAA"). For financial statement purposes, the
assets, liabilities and results of operations of PAA are included in our
consolidated financial statements, with the public unitholders' interest
reflected as a minority interest. Our upstream crude oil and natural gas
activities are focused in California (in the Los Angeles Basin, the Arroyo
Grande Field, and the Mt. Poso Field), offshore California (in the Point
Arguello Field), the Sunniland Trend of South Florida and the Illinois Basin in
southern Illinois. Our midstream activities are concentrated in California,
Texas, Oklahoma, Louisiana and the Gulf of Mexico.
UNAUTHORIZED TRADING LOSSES
In November 1999, we discovered that a former employee of PAA had engaged in
unauthorized trading activity, resulting in losses of approximately $162.0
million ($174.0 million, including estimated associated costs and legal expenses
at December 31, 1999). Approximately $154.9 million of the unauthorized trading
loss was recognized in 1999, with approximately $72.3 million and $114.9 million
of this amount recognized in the three and nine months ended September 30, 1999,
respectively. As a result, we have previously restated our 1999 financial
information. During the third quarter of 2000, we recognized an additional $6.6
million charge for litigation related to the unauthorized trading losses (See
Note 11 to the consolidated financial statements).
RESULTS OF OPERATIONS
Three Months Ended September 30, 2000 and 1999
For the three months ended September 30, 2000, we reported net income of $6.7
million, or $0.17 per basic share ($0.16 per diluted share) on total revenue of
$743.2 million, as compared with a net loss of $20.0 million, or $1.30 per basic
and diluted share on total revenue of $1.1 billion in the third quarter of 1999.
Results for the three months ended September 30, 2000 and 1999 include the
following special or nonrecurring items:
2000
. $6.6 million charge for litigation related to the unauthorized trading
losses; and
. $2.1 million of noncash compensation expense.
1999
. $72.3 million of unauthorized trading losses;
. $1.9 million of noncash compensation expense; and
. $1.0 million of restructuring expenses.
Excluding the items noted above, we would have reported net income of
approximately $9.6 million and $7.6 million for the three months ended September
30, 2000 and 1999, respectively. Adjusted EBITDA increased 9% in 2000 to $45.7
million from the $41.7 million reported in the third quarter of 1999. Adjusted
EBITDA means earnings before interest expense, income taxes, depreciation,
depletion and amortization and the nonrecurring items discussed above. Cash flow
from operations after deducting minority interest (net income before noncash
items) was $26.5 million and $23.9 million for the third quarters of 2000 and
1999, respectively. Cash flow from operations also excludes the nonrecurring
items discussed above.
Oil and natural gas sales. Oil and natural gas sales were $38.6 million for
the third quarter of 2000, an approximate 11% increase from the 1999 third
quarter amount of $34.7 million due to higher product prices ($6.4 million)
which was partially offset by decreased production volumes ($2.5 million).
22
<PAGE>
Marketing, transportation, storage and terminalling revenues. Marketing,
transportation, storage and terminalling revenues decreased to $703.9 million
for the third quarter of 2000 compared to the 1999 third quarter amount of $1.1
billion, due to higher crude oil prices which offset lower current year lease
gathering and bulk purchase volumes and decreased pipeline margin revenues.
Production expenses. Total production expenses decreased to $15.9 million from
$16.3 million in the third quarter of 1999 primarily due to the sale of certain
state of California emission credits, which are partially offset by increases in
operating costs, primarily for electricity and natural gas for fuel.
Marketing, transportation, storage and terminalling expenses. Marketing,
transportation, storage and terminalling expenses decreased to $671.8 million in
the third quarter of 2000 compared to $1.1 billion in the same quarter of 1999.
The decrease is primarily due to lower current year lease gathering and bulk
purchase volumes and a decrease in pipeline margin purchases partially offset by
increased purchase costs as a result of higher crude oil prices.
General and administrative. General and administrative expenses were $9.8
million for the third quarter of 2000 compared to $8.9 million for the third
quarter of 1999. Our upstream and midstream activities accounted for
approximately $0.5 million and $0.4 million, respectively, of the increase.
Nonrecurring or special items
Unauthorized trading losses. As previously discussed, we recognized losses
from unauthorized trading and related expenses, including litigation settlement
of approximately $6.6 million and $72.3 million in the third quarter of 2000 and
1999, respectively.
Noncash compensation expense. We recognized noncash compensation expense of
$2.1 million and $1.9 million in the third quarter of 2000 and 1999,
respectively, related to the probable vesting of partnership units granted by
PAA's general partner to certain officers and key employees of PAA's general
partner and its affiliates. The units granted are owned by the general partner
and therefore, do not reflect an increase in the number of units of the
partnership, nor a cash cost to PAA.
Restructuring charge. A $1.0 million restructuring charge, primarily
associated with personnel reduction, was incurred by PAA in the third quarter of
1999 and is included in marketing, transportation, storage and terminalling
expenses.
Upstream Results
The following table reflects certain of our upstream operating information for
the periods presented:
<TABLE>
<CAPTION>
Three Months Ended
September 30,
------------------------
2000 1999
---------- -----------
<S> <C> <C>
Average Daily Production Volumes (in thousands):
Barrels of oil equivalent ("BOE")
California onshore (approximately 91% oil) 15.4 15.9
Offshore California (100% oil) 3.9 4.5
Gulf Coast (100% oil) 2.3 2.9
Illinois Basin (100% oil) 2.8 3.0
---------- -----------
Total (approximately 94% oil) 24.4 26.3
========== ===========
Unit Economics:
Average sales price per BOE $ 17.20 $ 14.34
Production expense per BOE 7.10 6.75
---------- -----------
Gross margin per BOE 10.10 7.59
Upstream G&A expense per BOE 0.91 0.64
---------- -----------
Gross profit per BOE $ 9.19 $ 6.95
========== ===========
</TABLE>
23
<PAGE>
Total oil equivalent production decreased approximately 7% to an average of
24,400 BOE per day as compared to the third quarter 1999 average of 26,300 BOE
per day. Net daily production from our onshore California properties decreased
to 15,400 barrels per day in the third quarter of 2000 compared to 15,900
barrels per day in the prior year period primarily due to natural decline and
uplift volumes added by the capital program. Production volumes were also
adversely impacted by electrical brownouts in the LA Basin and Arroyo Grande,
high gas gathering system back-pressure in our Arroyo Grande Field and a change
in reporting volumes associated with the Inglewood Gas Plant. Net daily
production from our offshore California Point Arguello Unit decreased to 3,900
barrels per day in the third quarter of 2000 compared to 4,500 barrels per day
in the prior year period. This decrease is due primarily to an increase in our
MMS royalty burden rate beginning in July 2000, natural decline and
curtailments arising from gas cycling between producing and injection wells. Net
daily production for our Gulf Coast properties averaged approximately 2,300
barrels per day during the third quarter of 2000, compared to 2,900 barrels per
day in the prior year period primarily due to mechanical problems and natural
decline. Net daily production in the Illinois Basin averaged approximately 2,800
barrels per day during the third quarter of 2000, a decrease of approximately 7%
compared to 3,000 barrels per day during the third quarter of 1999, due
primarily to lower water injection levels, natural decline and the high demand
for completion units which has delayed completion of newly drilled wells and
routine well servicing.
Our average product price was $17.20 per BOE, up 20% as compared to the 1999
third quarter average wellhead price of $14.34 per BOE. Our product price
represents a combination of fixed-price and floating-price sales arrangements
and incorporates location and quality discounts from the benchmark NYMEX price.
The NYMEX benchmark WTI crude oil price averaged $31.66 per barrel during
the third quarter of 2000, approximately 46% above the $21.71 per barrel amount
in the prior year quarter. Our average product prices also include the effects
of hedging transactions such as financial swap and collar arrangements and
futures transactions. These transactions had the effect of decreasing our
average price by $9.88 and $2.19 per BOE in the third quarter of 2000 and 1999,
respectively. We maintained hedges on approximately 80% and 67% of our crude oil
production in the third quarter of 2000 and 1999, respectively.
Upstream unit gross margin (well-head revenue less production expenses) for
the third quarter of 2000 was $10.10 per BOE, a 33% increase as compared to
$7.59 per BOE reported for the third quarter of 1999. Average unit production
expenses averaged $7.10 per BOE for the third quarter of 2000 as compared to the
1999 third quarter average of $6.75 per BOE. The increase in production expenses
is primarily due to increased gas fuel costs, as well as general pressure
throughout the service industry.
Unit general and administrative expenses increased to $0.91 per BOE in the
third quarter of 2000, compared to $0.64 per BOE in the prior year comparative
quarter due to lower production volumes as well as increased costs. Total
upstream general and administrative expense was $2.1 million during the third
quarter of 2000 compared to $1.6 million in the third quarter of 1999. The
increase is primarily attributable to increased overhead expenses related to our
production and corporate activities, decreased capitalization of overhead costs
and to increased legal and consulting fees.
Total upstream DD&A remained constant at $5.3 million in the third quarter of
2000 as compared to the third quarter of 1999. An increase in our per unit DD&A
rate was offset by lower production volumes. On a per unit basis, DD&A was $2.21
for the third quarter of 2000 compared to $2.10 in the 1999 comparative quarter.
Midstream Results
Excluding the unauthorized trading losses, gross margin from our midstream
activities was $32.2 million in the third quarter of 2000 compared to $31.9
million in the third quarter of 1999. An analysis of these results is discussed
below.
The following table reflects certain of our midstream operating information
for the periods presented (in thousands):
<TABLE>
<CAPTION>
Three Months Ended
September 30,
-------------------------
2000 1999
----------- ------------
(restated)
<S> <C> <C>
Operating Results:
Gross margin:
Pipeline $ 11,886 $ 14,539
Gathering and marketing and
terminalling and storage 20,267 17,400
Unauthorized trading losses (6,600) (72,250)
----------- ------------
Total 25,553 (40,311)
General and administrative expense (7,780) (7,347)
----------- ------------
Gross profit $ 17,773 $(47,658)
=========== ============
</TABLE>
Table continued on following page
24
<PAGE>
<TABLE>
<CAPTION>
Three Months Ended
September 30,
-------------------------
2000 1999
----------- ------------
<S> <C> <C>
Average Daily Volumes (MBbls/day):
Pipeline Activities:
All American
Tariff activities 76 93
Margin activities 55 52
Other 100 106
----------- ------------
Total 231 251
=========== ============
Lease gathering 233 318
Bulk purchases 28 181
----------- ------------
Total 261 499
=========== ============
Terminal throughput 81 68
=========== ============
Storage leased to third parties,
monthly average volumes (MBbls/month) 1,687 1,687
=========== ============
</TABLE>
Pipeline Operations. Gross margin from pipeline operations was $11.9 million
for the quarter ended September 30, 2000 compared to $14.5 million for the prior
year quarter. Lower volumes shipped to West Texas as a result of the first
quarter 2000 sale of the California to Texas segment of the All American
Pipeline and movements to the Mojave station, which were discontinued in late
1999 after a new California pipeline was activated, account for the majority of
the decrease.
The margin between revenue and direct cost of crude purchased was $3.8 million
for the quarter ended September 30, 2000 compared to $10.2 million for the prior
year third quarter. Pipeline tariff revenues were approximately $11.4 million
for the third quarter of 2000 compared to approximately $12.4 million for the
same period in 1999, due to the sale of the All American Pipeline segment.
Pipeline operations and maintenance expenses decreased to $4.3 million for the
third quarter of 2000 compared to $7.1 million for the third quarter of 1999,
also due to the disposition.
Average daily pipeline volumes totaled 231,000 barrels per day and 251,000
barrels per day for the third quarter of 2000 and 1999, respectively. The volume
decrease is primarily due to the discontinued movements to the Mojave station,
as well as discontinued movements to West Texas as a result of the sale of the
segment of the All American Pipeline. Volumes on the All American Pipeline
decreased from an average of 145,000 barrels per day for the third quarter of
1999 to 131,000 barrels per day in the current year quarter due to the reasons
discussed above. All American's tariff volumes attributable to offshore
California production were about flat between the two periods. Tariff volumes
shipped on the Scurlock and West Texas gathering systems averaged 100,000
barrels per day and 106,000 barrels per day during the third quarters of 2000
and 1999, respectively.
Gathering and Marketing Activities and Terminalling and Storage Activities.
Excluding the unauthorized trading losses, gross margin from gathering,
marketing, terminalling and storage activities was approximately $20.3 million
for the quarter ended September 30, 2000, a 17% increase as compared to $17.4
million in the prior year quarter, primarily due to an increase in our per-
barrel margins due to the strong crude oil market. Gross revenues from
these activities were approximately $610.7 million and $869.8 million in the
third quarter of 2000 and 1999, respectively. The decreased revenues were
primarily due to lower bulk purchase and lease gathering volumes, offset by
higher crude prices.
Lease gathering volumes decreased from an average of 318,000 barrels per day
in the third quarter of 1999 to approximately 233,000 barrels per day in the
current year period. Bulk purchase volumes decreased from approximately 181,000
barrels per day in the 1999 third quarter to approximately 28,000 barrels per
day in the current year period. These decreases are primarily due to the phase
out of a significant amount of low-margin activity subsequent to the discovery
of the unauthorized trading losses. The gross margin impact from the reduced
volumes between the third quarter of 1999 and the current year quarter was
approximately $1.5 million. Lease gathering volumes averaged approximately
235,000 barrels per day and 229,000 barrels per day, respectively, for the first
and second quarters of 2000, while bulk purchases averaged 29,000 barrels per
day and 26,000 barrels per day for the same periods. These consecutive quarter
comparisons are more indicative of a trend analysis than a comparison to the
third quarter of 1999 due to the phase out of the low margin barrels.
25
<PAGE>
Terminal throughput, which includes both our Cushing and Ingleside terminals,
increased to 81,400 barrels per day from 67,900 barrels per day in the third
quarter of last year, while storage leased to third parties was about flat with
last year at 1.7 million barrels per month.
Midstream general and administrative expenses were $7.8 million for the
quarter ended September 30, 2000 compared to $7.3 million for the third quarter
in 1999. The increase in 2000 is primarily due to consulting and accounting
charges related to system modifications and enhancements and personnel-related
costs.
Midstream depreciation and amortization expense was $5.5 million for the
quarter ended September 30, 2000, compared to $4.7 million for the third quarter
of 1999. The increase reflects a reevaluation of certain criteria on which the
depreciation of certain fixed assets was based prior to the implementation of a
fixed asset reporting system in the third quarter of 2000. We estimate that
depreciation and amortization expense will average approximately $4.6 million to
$4.7 million per quarter in the future, based on our current property base.
Nine Months Ended September 30, 2000 and 1999
For the nine months ended September 30, 2000, we reported net income of $32.3
million, or $1.18 per basic share ($1.09 per diluted share) on total revenue of
$2.5 billion, as compared with a net loss of $28.3 million, or $2.09 per basic
and diluted share on total revenue of $2.5 billion in the first nine months of
1999. Results for the nine months ended September 30, 2000 and 1999 include the
following special or nonrecurring items:
2000
. a $28.1 million gain on the sale of crude oil linefill;
. a $20.1 million gain on the sale of the segment of the All American Pipeline
that extends from Emidio, California, to McCamey, Texas;
. $6.6 million charge for litigation related to the unauthorized trading
losses.
. $4.4 million of previously deferred net gains on interest rate swap
terminations recognized due to the early extinguishment of debt (net of
minority interest, this net gain had a negligible effect on income before
taxes);
. an extraordinary loss of $5.0 million related to the early extinguishment of
debt (net of minority interest and tax benefit);
. amortization of $4.6 million of debt issue costs associated with facilities
put in place during the fourth quarter of 1999;
. $2.3 million of noncash compensation expense; and
. $0.9 million gain recognized upon the transfer of 69,444 of our units in PAA
to employees of the general partner upon the vesting of transaction unit
grants.
1999
. $114.9 million of unauthorized trading losses;
. $1.9 million of noncash compensation expense; and
. $1.4 million of restructuring expenses.
Excluding the items noted above, we would have reported net income of
approximately $25.3 million and $14.4 million for the nine months ended
September 30, 2000 and 1999, respectively. Adjusted EBITDA increased 36% in 2000
to $133.9 million from the $98.3 million reported in the first nine months of
1999. Cash flow from operations after deducting minority interest (net income
before noncash items) was $75.1 million and $52.1 million in the first nine
months of 2000 and 1999, respectively. Cash flow from operations also excludes
the nonrecurring items discussed above.
Oil and natural gas sales. Oil and natural gas sales were $109.2 million for
the first nine months of 2000, an approximate 35% increase from the 1999 first
nine months amount of $81.0 million due to higher product prices and increased
production volumes, which contributed approximately $22.7 million and $5.5
million to the increase, respectively.
Marketing, transportation, storage and terminalling revenues. Marketing,
transportation, storage and terminalling revenues decreased to $2,347.8 million
for the first nine months of 2000 from the 1999 amount of $2,416.1 million. The
decrease is due primarily to lower current year volumes, partially offset by
higher crude oil prices.
Production expenses. Total production expenses increased to $46.6 million from
$40.0 million in the first nine months of 2000 and 1999, respectively, primarily
due to increased production volumes and increased fuel costs, as well as general
pressure throughout the service industry, offset by the sale of
certain state of California emission credits.
26
<PAGE>
Marketing, transportation, storage and terminalling expenses. Marketing,
transportation, storage and terminalling expenses decreased to $2,247.2 million
in the first nine months of 2000 compared to $2,338.9 million in the same period
in 1999. The decrease is primarily due lower current year volumes purchased,
partially offset by higher crude oil prices.
General and administrative. General and administrative expenses were $31.3
million for the first nine months of 2000 compared to $20.6 million for the
first nine months of 1999. Our upstream and midstream activities accounted for
approximately $2.0 million and $8.7 million, respectively, of the increase from
1999 to 2000.
Depreciation, depletion and amortization. Primarily as a result of our mid-
1999 midstream acquisitions, increased amortization of debt issue costs related
to facilities put in place during the fourth quarter of 1999 and increased
upstream production levels, total DD&A for the first nine months of 2000 was
$36.1 million as compared to $25.6 million for the first nine months of 1999.
Interest expense. Interest expense for the first nine months of 2000 was $41.9
million, an increase of $9.2 million over the first nine months of 1999. The
increase is primarily due to a higher average debt level in 2000 resulting from
our 1999 midstream acquisitions and the unauthorized trading losses, as well as
increased interest rates. Capitalized interest was approximately $3.2 million
for the nine months ended September 30, 2000 and 1999.
Nonrecurring items
Unauthorized trading losses. As previously discussed, we recognized losses
from unauthorized trading and related expenses, including litigation settlement
of approximately $6.6 million and $114.9 million in the first nine months of
2000 and 1999, respectively.
Gain on sale of linefill. We initiated the sale of 5.2 million barrels of
crude oil linefill from the All American Pipeline in November 1999. The sale was
completed in March 2000. We recognized a gain of $28.1 million in connection
with the sale of the linefill in the first quarter of 2000.
Gain on sale of pipeline segment. On March 24, 2000, we completed the sale of
the segment of the All American Pipeline that extends from Emidio, California to
McCamey, Texas to a unit of El Paso Energy Corporation for proceeds of
approximately $124.0 million, which are net of associated transaction costs and
estimated costs to remove certain equipment. We recognized a total gain of $20.1
million in connection with the sale in the first quarter of 2000.
Early extinguishment of debt. During the nine months ended September 30, 2000,
we recognized extraordinary losses, consisting primarily of unamortized debt
issue costs, totaling $5.0 million (net of minority interest of $7.0 million and
deferred tax of $3.2 million) related to the permanent reduction of the All
American Pipeline, L.P. term loan facility and the refinancing of PAA's credit
facilities. In addition, interest and other income for the nine months ended
September 30, 2000 includes $4.4 million of net deferred gains from terminated
interest rate swaps as a result of the debt extinguishments.
Noncash compensation expense. We recognized noncash compensation expense of
$2.3 million and $1.9 million for the nine months ended September 30, 2000 and
1999, respectively, related to the probable vesting of partnership units granted
by PAA's general partner to certain officers and key employees of PAA's general
partner and its affiliates. The units granted are owned by the general partner
and therefore, do not reflect an increase in the number of units of the
partnership, nor a cash cost to PAA.
Transaction grant gain. Upon the transfer of 69,444 of our units in PAA to
employees of the general partner, a gain of $0.9 million was recognized which
represented the difference between the market price on the date of vesting and
our basis in the units.
Restructuring charge. A $1.4 million restructuring charge, primarily
associated with personnel reduction was incurred by PAA in the first quarter of
1999. Approximately $1.1 million is included in marketing, transportation,
storage and terminalling expenses and approximately $0.3 million is included in
general and administrative expenses.
27
<PAGE>
Upstream Results
The following table reflects certain of our upstream operating information for
the periods presented:
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
------------------------
2000 1999
---------- -----------
<S> <C> <C>
Average Daily Production Volumes (in thousands):
Barrels of oil equivalent
California onshore (approximately 91% oil) 15.1 15.5
Offshore California (100% oil) 4.2 1.5
Gulf Coast (100% oil) 2.2 2.7
Illinois Basin (100% oil) 2.8 3.1
---------- -----------
Total (approximately 95% oil) 24.3 22.8
========== ===========
Unit Economics:
Average sales price per BOE $ 16.40 $ 12.99
Production expense per BOE 7.00 6.41
---------- -----------
Gross margin per BOE 9.40 6.58
Upstream G&A expense per BOE 1.05 0.81
---------- -----------
Gross profit per BOE $ 8.35 $ 5.77
========== ===========
</TABLE>
Total oil equivalent production increased approximately 6% to an average of
24,300 BOE per day as compared to the first nine months 1999 average of 22,800
BOE per day. The increase is attributable to the offshore California
Point Arguello Unit, which we acquired from Chevron in July 1999. Net daily
production from our onshore California properties decreased to 15,100 barrels
per day in the first nine months of 2000 compared to 15,500 barrels per day in
the prior period primarily due to electrical brownouts in the LA Basin and
Arroyo Grande and natural decline. Net daily production for our Gulf Coast
properties averaged approximately 2,300 barrels per day during the first nine
months of 2000, compared to 2,700 barrels per day in the prior period. The Gulf
Coast production decrease is due to downtime as a result of mechanical problems
and the effects of natural decline. Net daily production in the Illinois Basin
averaged approximately 2,800 barrels per day during the first nine months of
2000, compared to 3,100 barrels per day during the first nine months of 1999,
due primarily to lower water injection levels, natural decline and the high
demand for completion units which has delayed completion of newly drilled wells
and routine well servicing.
Our average product price was $16.40 per BOE, up 26% as compared to the 1999
first nine months average wellhead price of $12.99 per BOE. Our product price
represents a combination of fixed-price and floating-price sales arrangements
and incorporates location and quality discounts from the benchmark NYMEX price.
The NYMEX benchmark WTI crude oil price averaged $29.70 per barrel during the
first nine months of 2000, approximately 70% above the $17.47 per barrel amount
in the prior year period. Our average product prices also include the effects of
hedging transactions such as financial swap and collar arrangements and futures
transactions. These transactions had the effect of decreasing our average price
by $8.55 per BOE and $0.22 per BOE in the first nine months of 2000 and 1999,
respectively. We maintained hedges on approximately 81% and 61% of our crude oil
production in the first nine months of 2000 and 1999, respectively.
Upstream unit gross margin (well-head revenue less production expenses) for
the first nine months of 2000 was $9.40 per BOE, a 43% increase as compared to
$6.58 per BOE reported for the first nine months of 1999. Average unit
production expenses averaged $7.00 per BOE for the first nine months of 2000, an
approximate 9% increase over the 1999 first nine months average of $6.41 per
BOE. The increase in production expenses is primarily due to increased gas fuel
costs, as well as general pressure throughout the service industry.
Unit general and administrative expenses increased to $1.05 per BOE in the
first nine months of 2000, compared to $0.81 per BOE in the prior year
comparative period. Total upstream general and administrative expense was $7.0
million during the first nine months of 2000 compared to $5.0 million in the
first nine months of 1999. The increase is primarily attributable to increased
overhead costs related to our production and corporate activities, decreased
capitalization of overhead costs and to increased legal and consulting fees.
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<PAGE>
Total upstream DD&A was $15.7 million in the first nine months of 2000
compared to $14.1 million in the first nine months of 1999. The increase is
primarily due to increased production volumes as well as an increase in our per
unit DD&A rate. On a per unit basis, DD&A was $2.21 for the first nine months of
2000 compared to $2.10 in the 1999 comparative period.
Midstream Results
Excluding the unauthorized trading losses, gross margin from our midstream
activities was $100.7 million in the first nine months of 2000 compared to $77.2
million in the first nine months of 1999. An analysis of these results is
discussed below.
The following table reflects certain of our midstream operating information
for the periods presented (in thousands):
Nine Months Ended
September 30,
-------------------------
2000 1999
----------- ------------
(restated)
Operating Results:
Gross Margin:
Pipeline $ 37,802 $ 39,338
Gathering and marketing and
terminalling and storage 62,861 37,905
Unauthorized trading losses (6,600) (114,925)
----------- ------------
Total 94,063 (37,682)
General and administrative expense (24,295) (15,581)
----------- ------------
Gross profit $ 69,768 $ (53,263)
=========== ============
Average Daily Volumes (barrels):
Pipeline Activities:
All American
Tariff activities 74 106
Margin activities 57 54
Other 106 43
----------- ------------
Total 237 203
=========== ============
Lease gathering 223 216
Bulk purchases 28 138
----------- ------------
Total 251 354
=========== ============
Terminal throughput 64 75
=========== ============
Storage leased to third parties,
monthly average volumes (MBbls/month) 1,489 1,920
=========== ============
Pipeline Operations. Gross margin from pipeline operations was $37.8 million
for the nine months ended September 30, 2000 compared to $39.3 million for the
prior year period. Increased margins from the Scurlock and West Texas gathering
system acquisitions in mid-1999 were offset by lower tariff transport volumes
and reduced margins on our pipeline merchant activity. Tariff volumes decreased
due to lower production from Exxon's Santa Ynez Field and the Point Arguello
Field, both offshore California, and the sale of the segment of the All American
Pipeline. Margins from pipeline merchant activity were lower due to the sale of
the segment of the All American Pipeline.
The margin between revenue and direct cost of crude purchased was $14.0
million for the nine months ended September 30, 2000 compared to $22.9 million
for the first nine months of the prior year. Pipeline tariff revenues were
approximately $36.0 million for the first nine months of 2000 compared to
approximately $36.5 million for the same period in 1999 as increases related to
the Scurlock and West Texas gathering system acquisitions were partially offset
by the sale of the segment of the All American Pipeline segment. Pipeline
operations and maintenance expenses were approximately $12.2 million for the
first nine months of 2000 compared to $20.1 million for the first nine months of
1999, also due to the acquisitions and disposition.
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<PAGE>
Average daily pipeline volumes totaled 237,000 barrels per day and 203,000
barrels per day for the first nine months of 2000 and 1999, respectively.
Volumes on the All American Pipeline decreased from an average of 160,000
barrels per day for the first nine months of 1999 to 131,000 barrels per day in
the current year period due to the reasons discussed above. All American's
tariff volumes attributable to offshore California production were approximately
74,000 barrels per day for nine months ended September 30, 2000 compared to
81,000 barrels per day in the prior year period. Tariff volumes shipped on the
Scurlock and West Texas gathering systems averaged 106,000 barrels per day and
43,000 barrels per day during the first nine months of 2000 and 1999,
respectively. The 1999 period includes volumes for Scurlock effective May 1,
1999, and West Texas gathering system volumes effective July 1, 1999.
Gathering and Marketing Activities and Terminalling and Storage Activities.
Excluding the unauthorized trading losses, gross margin from gathering,
marketing, terminalling and storage activities was approximately $62.9 million
for the nine months ended September 30, 2000 compared to $37.9 million in the
prior year period. The increase in gross margin is primarily due to an increase
in lease gathering volumes as a result of the Scurlock acquisition and increased
per barrel margins due to the strong crude oil market. Gross revenues from
gathering, marketing, terminalling and storage activities were approximately
$2.0 billion and $1.8 billion in the first nine months of 2000 and 1999,
respectively, as increased revenues resulting from higher crude oil prices and
lease gathering volumes were partially offset by decreased revenues from lower
bulk purchase volumes.
Lease gathering volumes increased from an average of 216,000 barrels per day
for the first nine months of 1999 to approximately 223,000 barrels per day for
the 2000 period due to the Scurlock acquisition, partially offset by a
significant amount of low margin barrels that were phased out subsequent to the
discovery of the trading losses. Bulk purchase volumes decreased from
approximately 138,000 barrels per day for the first nine months of 1999 to
approximately 28,000 barrels per day in the current year period, also due to the
phase out of low margin barrels. The gross margin impact from the reduced
volumes was approximately $6.0 million for the nine months ended September 30,
2000.
Terminal throughput, which includes both our Cushing and Ingleside terminals,
was 64,000 and 75,000 barrels per day for the nine months ended September 30,
2000 and 1999, respectively. Storage leased to third parties was 1.5 million
barrels per month and 1.9 million barrels per month for the same periods,
respectively.
Midstream general and administrative expenses were $24.3 million for the nine
months ended September 30, 2000, compared to $15.6 million for the first nine
months of 1999. The increase in 2000 is primarily due to the Scurlock
acquisition in May 1999 (approximately $5.7 million), consulting fees related to
the trading loss investigation, consulting and accounting charges related to
system modifications and enhancements and personnel-related costs.
Midstream depreciation and amortization expense was $20.3 million for the nine
months ended September 30, 2000, compared to $11.4 million for the first nine
months of 1999. The increase is primarily due to the Scurlock and West Texas
gathering system acquisitions in mid-1999, the previously discussed adjustments
in connection with the implementation of a new fixed asset reporting system and
increased amortization of debt issue costs associated with facilities put in
place during the fourth quarter of 1999 due to the unauthorized trading losses.
These increases were partially offset by decreased depreciation related to the
segment of the All American Pipeline that was sold in the first quarter of 2000.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flow
Nine Months Ended
September 30,
-------------------------
(in millions) 2000 1999
--------------------------------------------------------------
(restated)
Cash provided by (used in):
Operating activities $ 17.5 $ 8.0
Investing activities 164.9 (239.0)
Financing activities (240.8) 228.4
--------------------------------------------------------------
Operating Activities. Net cash provided by operating activities for the first
nine months of 2000 decreased from the 1999 amount primarily due to amounts paid
during the first quarter of 2000 for the 1999 unauthorized trading losses,
partially offset by increased income before taxes between the two periods.
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<PAGE>
Investing Activities. Net cash provided by investing activities for the first
nine months of 2000 included $223.9 million of proceeds from the sales of the
segment of the All American Pipeline and pipeline linefill and approximately
$49.9 million and $6.9 million of upstream and midstream capital expenditures,
respectively.
Financing activities. Net cash used in financing activities for the first nine
months of 2000 resulted primarily from net payments of $201.6 million of short-
term and long-term debt. Proceeds used to reduce debt primarily came from the
asset sales discussed above.
On April 1, 2000, we paid aggregate cash dividends of approximately $6.0
million on our Series D, F and G preferred stock. The dividends on the Series D
preferred stock are for the period from January 1, 2000 through March 31, 2000.
The Series F preferred stock was issued on December 15, 1999 and such dividend
covers the period from that date through March 31, 2000. The dividends on the
Series G preferred stock are for the period from October 1, 1999 through March
31, 2000.
On July 19, 2000, we paid cash dividends of approximately $0.4 million on our
Series D preferred stock covering the period from April 1, 2000 through June 30,
2000.
On October 1, 2000, we paid aggregate cash dividends of approximately $7.0
million on our Series D, F and G preferred stock. The dividends on the Series D
preferred stock are for the period from July 1, 2000 through September 30, 2000.
The dividends on the Series F and G preferred stock are for the period from
April 1, 2000 through September 30, 2000.
Credit Facilities
We have a $225.0 million revolving credit facility with a group of banks. The
revolving credit facility is guaranteed by all of our upstream subsidiaries and
is collateralized by our upstream oil and natural gas properties and those of
the guaranteeing subsidiaries and the stock of all upstream subsidiaries. The
borrowing base under the revolving credit facility at September 30, 2000, is
$225.0 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 crude oil and natural gas loans to borrowers similar to our company. Our
borrowing base may be affected from time to time by the performance of our oil
and natural gas properties and changes in oil and natural gas prices. We incur 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, 2002, at which
time the remaining outstanding balance converts to a term loan which is
repayable in twelve equal quarterly installments commencing October 1, 2002,
with a final maturity of July 1, 2005. The revolving credit facility bears
interest, at our option of either LIBOR plus 1 3/8% or Base Rate (as defined
therein). At September 30, 2000, there were letters of credit of $0.6 million
and borrowings of $13.0 million outstanding on the revolving credit facility.
The revolving credit facility contains covenants which, among other things,
prohibit the payment of cash dividends on common stock, limit repurchases of
common stock, limit the amount of consolidated debt, limit our ability to make
certain loans and investments and provide that we must maintain a specified
relationship between current assets and current liabilities. We are in
compliance with the covenants contained in the revolving credit facility. At
September 30, 2000, we could have borrowed the full $225.0 million available
under the revolving credit facility.
On May 8, 2000, PAA entered into new bank credit agreements. The borrower
under the new facilities is Plains Marketing, L.P. PAA is a guarantor of the
obligations under the credit facilities. The obligations are also guaranteed by
the subsidiaries of Plains Marketing, L.P. PAA entered into the credit
agreements in order to:
. refinance the existing bank debt of Plains Marketing, L.P. and Plains
Scurlock Permian, L.P. in conjunction with the merger of Plains Scurlock
Permian, L.P. into All American Pipeline, L.P.;
. refinance existing bank debt of All American Pipeline, L.P.;
. repay us $114.0 million plus accrued interest of subordinated debt, and
. provide additional flexibility for working capital, capital expenditures, and
for other general corporate purposes.
PAA's new bank credit agreements consist of:
. a $400.0 million senior secured revolving credit facility. The revolving
credit facility is secured by substantially all of PAA's assets and matures
in April 2004. No principal is scheduled for payment prior to maturity. The
revolving credit facility bears interest at PAA's option at either the base
rate, as defined, plus an applicable margin, or LIBOR plus an applicable
margin. PAA incurs a commitment fee on the unused portion of the revolving
credit facility. At September 30, 2000, $292.0 million was outstanding on
the revolving credit facility.
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<PAGE>
. A $300.0 million senior secured letter of credit and borrowing facility, the
purpose of which is to provide standby letters of credit to support the
purchase and exchange of crude oil for resale and borrowings to finance crude
oil inventory that has been hedged against future price risk. The letter of
credit facility is secured by substantially all of PAA's assets and has a
sublimit for cash borrowings of $100 million to purchase crude oil that has
been hedged against future price risk. The letter of credit facility expires
in April 2003. 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 of PAA's current assets and current
liabilities (primarily inventory and accounts receivable and accounts payable
related to the purchase and sale of crude oil). At September 30, 2000,
approximately $79.5 million in letters of credit were outstanding under the
letter of credit and borrowing facility.
PAA's bank credit agreements prohibit distributions on, or purchases or
redemptions of, units if any default or event of default is continuing. In
addition, the agreements contain various covenants limiting PAA's ability to,
among other things:
. incur indebtedness;
. grant liens;
. sell assets;
. make investments;
. engage in transactions with affiliates;
. enter into prohibited contracts; and
. enter into a merger or consolidation.
PAA's bank credit agreements treat a change of control as an event of default
and also require PAA to maintain:
. a current ratio (as defined) of 1.0 to 1.0;
. a debt coverage ratio that is not greater that 4.0 to 1.0 for the period from
March 31, 2000 to March 31, 2002 and subsequently 3.75 to 1.0;
. an interest coverage ratio that is not less than 2.75 to 1.0; and
. a debt to capital ratio of not greater than 0.65 to 1.0.
A default under PAA's bank credit agreements would permit the lenders to
accelerate the maturity of the outstanding debt and to foreclose on the assets
securing the credit facilities. As long as PAA is in compliance with its bank
credit agreements, they do not restrict its ability to make distributions of
"available cash" as defined in its partnership agreement. PAA is currently in
compliance with the covenants in its bank credit agreements. At September 30,
2000, PAA could have borrowed the full $400.0 million under its secured
revolving credit facility.
Contingencies
Since our announcement in November 1999 of PAA's losses resulting from
unauthorized trading by a former employee, numerous class action lawsuits have
been filed against PAA, certain of its general partner's officers and directors
and in some of these cases, its general partner and us alleging violations of
the federal securities laws. In addition, derivative lawsuits were filed against
PAA's general partner, its directors and certain of its officers alleging the
defendants breached the fiduciary duties owed to PAA and its unitholders by
failing to monitor properly the activities of its traders. See Part II - "Other
Information" - Item 1. - "Legal Proceedings."
Although we maintain an inspection program designed to prevent and, as
applicable, to detect and address releases of crude oil into the environment
from our pipeline and storage operations, we may experience such releases in the
future, or discover releases that were previously unidentified. Damages and
liabilities incurred due to any future environmental releases from our assets
may substantially affect our business.
OUTLOOK
Our upstream activities are affected by changes in crude oil prices, which
historically have been volatile. The NYMEX benchmark WTI crude oil price
averaged $29.70 per barrel during the first nine months of 2000, approximately
70% above the $17.47 per barrel in the first nine months of last year.
Substantial future crude oil price declines would adversely affect our overall
results, and therefore our liquidity. Furthermore, low crude oil prices could
affect our ability to raise capital on favorable terms. In order to manage our
exposure to commodity price risk, we have routinely hedged a portion of our
crude oil production and intend to continue this practice. For the fourth
quarter of 2000, we have entered into various arrangements which provide for us
to receive an average minimum NYMEX WTI price of $16.25 per barrel on 18,500
barrels of oil per day. Approximately 10,000 barrels per day of these volumes
will participate in price increases up to $19.75 per barrel. This
32
<PAGE>
hedge position is equivalent to approximately 80% of our third quarter 2000
average daily crude oil volumes. At average third quarter prices we would
realize an average NYMEX price of $18.50 per barrel for the hedged volumes. For
2001, we have entered into various arrangements, using a combination of swaps,
collars and purchased puts and calls, which will provide for us to receive an
average minimum NYMEX price of approximately $22.75 per barrel on 20,500 barrels
per day (equivalent to 89% of third quarter 2000 crude oil production levels)
with full market price participation up to an average of $27.00 per barrel.
Utilizing third quarter 2000 production levels at market prices between $26.00
and $36.00 per barrel, we will receive between 100% to 89% of market price and
at market prices over $36.00 per barrel, we will receive at least 89% of market
price. For 2002, we have entered into various arrangements that provide for us
to receive an average minimum NYMEX WTI price of $23.00 per barrel on 10,000
barrels per day (equivalent to 44% of third quarter 2000 production levels) with
full market price participation up to an average of $24.90 per barrel. At market
prices between $24.90 and $36.00 per barrel, we will receive between 100% and
92% of the market price and at market prices over $36.00 per barrel we will
receive at least 92% of market price. The foregoing NYMEX WTI crude oil prices
are before quality and location differentials and the cost of the year 2001 and
2002 hedges, which averaged approximately $0.80 and $0.70 per hedged barrel,
respectively. Management intends to continue to maintain hedging arrangements
for a significant portion of our production. Such contracts may expose us to the
risk of financial loss in certain circumstances.
There is upward pressure on operating expenses industry-wide due to increased
fuel costs for both gas and electricity, as well as general pressure throughout
the service industry.
As is common with most merchant activities, our ability to generate a profit
on our midstream margin activities is not tied to the absolute level of crude
oil prices but is generated by the difference between the price paid and other
costs incurred in the purchase of crude oil and the price at which we sell crude
oil. The gross margin generated by tariff activities depends on the volumes
transported on the pipeline and the level of the tariff charged, as well as the
fixed and variable costs of operating the pipeline. These operations are
affected by overall levels of supply and demand for crude oil.
ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for
Derivative Instruments and Hedging Activities ("SFAS 133"). SFAS 133 was
subsequently amended (i) in June 1999 by SFAS No. 137, Accounting for Derivative
Instruments and Hedging Activities - Deferral of the effective date of FASB
Statement No. 133 ("SFAS 137"), which deferred the effective date of SFAS 133 to
fiscal years beginning after June 15, 2000; and (ii) in June 2000 by SFAS 138,
"Accounting for Certain Derivative Instruments and Certain Hedge Activities,"
which amended certain provisions, inclusive of the definition of the normal
purchase and sale exclusion.
SFAS 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 so,
the type of hedge transaction. For fair value hedge transactions in which we are
hedging changes in the fair value of an asset, liability, or firm commitment,
changes in the fair value of the derivative instrument will generally be offset
in the income statement by changes in the fair value of the hedged item. For
cash flow hedge transactions, in which we are 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 ineffective portion of all hedges will be recognized in
earnings in the current period.
We will adopt SFAS 133, as amended, effective January 1, 2001. We believe we
have identified all instruments currently in place that will be subject to the
requirements of SFAS 133, however, due to the complex nature of SFAS 133 and
various interpretations regarding applications of SFAS 133 to certain
instruments, we have not fully determined what impact the adoption of SFAS 133
would have on the consolidated balance sheets, statements of operations and cash
flows. The FASB has formed a derivative implementation group which is addressing
assessment and implementation matters regarding the application of SFAS 133 for
consideration by the FASB. Adoption of this standard could increase volatility
in earnings and retained earnings (deficit) through comprehensive income.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
We are exposed to various market risks, including volatility in crude oil
commodity prices and interest rates. To manage our exposure, we monitor our
inventory levels, and our expectations of future commodity prices and interest
rates when making decisions with respect to risk management. We do not enter
into derivative transactions for speculative trading
33
<PAGE>
purposes that would expose us to price risk. Substantially all of our derivative
contracts are exchanged or traded with major financial institutions and the risk
of credit loss is considered remote.
Commodity Price Risk. The fair value of outstanding derivative commodity
instruments and the change in fair value that would be expected from a 10
percent price increase are shown in the table below (in millions):
<TABLE>
<CAPTION>
September 30, 2000 December 31, 1999
------------------------- -------------------------
Effect of Effect of
10% 10%
Fair Price Fair Price
Value Change Value Change
--------- -------- ------- -----------
<S> <C> <C> <C> <C>
Crude oil :
Futures contracts $ 6.1 $ 4.9 $ - $(2.8)
Swaps and options contracts (24.0) (15.3) (22.0) (6.2)
</TABLE>
The fair values of the futures contracts are based on quoted market prices
obtained from the NYMEX. The fair value of the swaps is estimated based on
quoted prices from independent reporting services compared to the contract price
of the swap and approximate the gain or loss that would have been realized if
the contracts had been closed out at the dates indicated. All hedge positions
offset physical positions exposed to the cash market; none of these offsetting
physical positions are included in the above table. Price-risk sensitivities
were calculated by assuming an across-the-board 10 percent increase in prices
regardless of term or historical relationships between the contractual price of
the instruments and the underlying commodity price. In the event of an actual 10
percent change in prompt month crude oil prices, the fair value of our
derivative portfolio would typically change less than that shown in the table
due to lower volatility in out-month prices.
For the fourth quarter of 2000, we have entered into various arrangements
which provide for us to receive an average minimum NYMEX WTI price of $16.25 per
barrel on 18,500 barrels of oil per day. Approximately 10,000 barrels per day of
these volumes will participate in price increases up to $19.75 per barrel. For
2001, we have entered into various arrangements, using a combination of swaps,
collars and purchased puts and calls, which will provide for us to receive an
average minimum NYMEX price of approximately $22.75 per barrel on 20,500 barrels
per day with full market price participation up to an average of $27.00 per
barrel. For 2002, we have entered into various arrangements that provide for us
to receive an average minimum NYMEX WTI price of $23.00 per barrel on 10,000
barrels per day with full market price participation up to an average of $24.90
per barrel. Location and quality differentials attributable to our properties
are not included in the foregoing prices. The agreements provide for monthly
settlement based on the differential between the agreement price and the actual
NYMEX crude oil price. Gains or losses are recognized in the month of related
production and are included in crude oil and natural gas sales. Such contracts
resulted in a reduction in revenues of $22.2 million and $56.7 million in the
third quarter and first nine months of 2000, respectively. The unrealized loss
at September 30, 2000, with respect to such contracts was $24.0 million.
At September 30, 2000, our hedging activities included crude oil futures
contracts maturing through 2001, covering approximately 6.9 million barrels of
crude oil. Since such contracts are designated as hedges and correlate to price
movements of crude oil, any gains or losses resulting from market changes will
be largely offset by losses or gains on our hedged inventory or anticipated
purchases of crude oil. Such contracts resulted in a reduction in revenues of
$1.2 million in the third quarter of 2000 and an increase in revenues of $0.1
million in the nine months ended September 30, 2000. The unrealized loss at
September 30, 2000, with respect to such contracts was $7.0 million.
Interest Rate Risk. Our debt instruments are sensitive to market fluctuations
in interest rates. Our variable rate debt bears interest at LIBOR plus the
applicable margin. At September 30, 2000, the carrying value of all variable
rate bank debt of $305.0 million approximated the fair value and liquidation
value at that date. The carrying value and fair value of the fixed rate debt was
$277.0 million and $282.1 million, respectively, at that date. The carrying
value and estimated fair value of redeemable preferred stock were $137.7 million
and $198.3 million, respectively, at September 30, 2000. At December 31, 1999,
the carrying value of all variable rate bank debt and the redeemable preferred
stock of $506.1 million and $138.8 million, respectively, approximated the fair
value and liquidation value at that date. The carrying value and fair value of
the fixed rate debt was $277.5 million and $270.7 million, respectively, at that
date. The fair value of fixed rate debt was based on quoted market prices based
on trades of our subordinated debt.
Interest rate swaps and collars are used to hedge underlying debt obligations.
These instruments hedge specific debt issuances and qualify for hedge
accounting. The interest rate differential is reflected as an adjustment to
interest expense over the life of the instruments. At September 30, 2000, we had
interest rate swap and collar arrangements for an aggregate notional principal
amount of $240.0 million, which positions had an aggregate value of
approximately $0.6 million as of such date. These instruments are based on LIBOR
and generally provide for a floor of 5% and a ceiling of 6.5% for $90.0
million of debt, a floor of 6% and a ceiling of 8% for $125.0 million of debt
and 5.7% for $25.0 million of debt.
34
<PAGE>
Forward-Looking Statements and Associated Risks
All statements, other than statements of historical fact, included in this
report are forward-looking statements, including, but not limited to, statements
identified by the words "anticipate," "believe," "estimate," "expect,"
"plan," "intend" and "forecast" and similar expressions and statements
regarding our business strategy, plans and objectives of our management for
future operations. These statements reflect our current views with respect to
future events, based on what we believe are reasonable assumptions. These
statements, however, are subject to certain risks, uncertainties and
assumptions, including, but not limited to:
. uncertainties inherent in the exploration for and development and production
of oil and gas and in estimating reserves;.
. unexpected future capital expenditures (including the amount and nature
thereof);
. impact of crude oil price fluctuations;
. the effects of competition;
. the success of our risk management activities;
. the availability (or lack thereof) of acquisition or combination
opportunities;
. the availability of adequate supplies of and demand for crude oil in areas of
midstream operations;
. the impact of current and future laws and governmental regulations;
. environmental liabilities that are not covered by an indemnity or insurance,
and
. general economic, market or business conditions.
If one or more of these risks or uncertainties materialize, or if underlying
assumptions prove incorrect, actual results may vary materially from those in
the forward-looking statements. Except as required by applicable securities
laws, we do not intend to update these forward-looking statements and
information.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Texas Securities Litigation. On November 29, 1999, a class action lawsuit was
filed in the United States District Court for the Southern District of Texas
entitled Di Giacomo v. Plains All American Pipeline, L.P. ("PAA"), et al. The
suit alleged that PAA and certain of its general partner's officers and
directors violated federal securities laws, primarily in connection with
unauthorized trading by a former employee. An additional nineteen cases have
been filed in the Southern District of Texas, some of which name the general
partner and us as additional defendants. All of the federal securities claims
are being consolidated into two actions. The first consolidated action is that
filed by purchasers of our common stock and options, and is captioned Koplovitz
v. Plains Resources Inc., et al. The second consolidated action is that filed by
purchasers of PAA's common units, and is captioned Di Giacomo v. Plains All
American Pipeline, L.P., et al. Plaintiffs alleged that the defendants were
liable for securities fraud violations under Rule 10b-5 and Section 20(a) of the
Securities Exchange Act of 1934 and for making false registration statements
under Sections 11 and 15 of the Securities Act of 1933.
We and PAA have reached an agreement in principle with representatives of the
plaintiffs for the settlement of all of the federal securities actions.
Aggregate amounts to be paid under the agreement in principle total
approximately $29.5 million plus interest from October 1, 2000 through the date
actual proceeds are remitted to representatives for the plaintiffs. Our
insurance carrier has deposited $15.0 million to an escrow account to fund
amounts payable under our insurance policies. The Boards of Directors of PAA and
Plains Resources have formed special independent committees to review and
approve final allocation of the settlement costs between PAA and us. Based on an
estimate of such allocation, which allocation is currently under review by the
committees, in the third quarter of 2000 we accrued an additional $6.6 million
of litigation costs and related expenses, which reduced basic earnings per
common share after minority interest and taxes for the three and nine months
ended September 30, 2000 by $0.12 ($0.11 diluted) and $0.12 ($0.07 diluted),
respectively.
The settlement is subject to a number of conditions, including negotiation and
finalization of a stipulation and agreement of settlement and related
documentation, and approval of the United States District Court for the Southern
District of Texas. The agreement in principle does not affect the Texas
Derivative Litigation and Delaware Derivative Litigation described below.
Texas Derivative Litigation. On July 11, 2000, a derivative lawsuit was filed
in the United States District Court for the Southern District of Texas entitled
Fernandez v. Plains All American Inc., et al., naming the general partner, its
directors and certain of its officers as defendants. This lawsuit contains the
same claims and seeks the same relief as the Delaware derivative litigation
described below. A motion to dismiss was filed on behalf of the defendants on
August 14, 2000.
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Delaware Derivative Litigation. On December 3, 1999, two derivative lawsuits
were filed in the Delaware Chancery Court, New Castle County, entitled Susser v.
Plains All American Inc., et al and Senderowitz v. Plains All American Inc., et
al. These suits, and three others which were filed in Delaware subsequently,
named the general partner, its directors and certain of its officers as
defendants, and allege that the defendants breached the fiduciary duties that
they owed to PAA and its unitholders by failing to monitor properly the
activities of its employees. The court has consolidated all of the cases under
the caption In Re Plains All American Inc. Shareholders Litigation, and has
designated the complaint filed in Sussex v. Plains All American Inc. as the
operative complaint in the consolidated action. A motion to dismiss was filed on
behalf of the defendants on August 11, 2000.
The plaintiffs in the Delaware securities litigation seek that the defendants
(1) account for all losses and damages allegedly sustained by Plains All
American from the unauthorized trading losses, (2) establish and maintain
effective internal controls ensuring that PAA's affiliates and persons
responsible for its affairs do not engage in wrongful practices detrimental to
Plains All American, (3) account for the plaintiffs' costs and expenses in
litigation, including reasonable attorneys' fees, accountants' fees, and
experts' fees and (4) provide the plaintiffs any additional relief as may be
just and proper under the circumstances.
We intend to vigorously defend the claims made against us in the Texas
derivative litigation and the Delaware derivative litigation. However, there can
be no assurance that we will be successful in our defense or that these lawsuits
will not have a material adverse effect on our financial position, results of
operations or cash flows.
On July 9, 1987, Exxon Corporation ("Exxon") filed an interpleader action in
the United States District Court for the Middle District of Florida, Exxon
Corporation v. E. W. Adams, et al., Case Number 87-976-CIV-T-23-B. This action
was filed by Exxon to interplead royalty funds as a result of a title
controversy between certain mineral owners in a field in Florida. One group of
mineral owners, John W. Hughes, et al. (the "Hughes Group"), filed a
counterclaim against Exxon alleging fraud, conspiracy, conversion of funds,
declaratory relief, federal and Florida RICO, breach of contract and accounting,
as well as challenging the validity of certain oil and natural gas leases owned
by Exxon, and seeking exemplary and treble damages. In March 1993, but effective
November 1, 1992, Calumet Florida Inc. ("Calumet"), our wholly owned subsidiary,
acquired all of Exxon's leases in the field affected by this lawsuit. In order
to address those counterclaims challenging the validity of certain oil and
natural gas leases, which constitute approximately 10% of the land underlying
this unitized field, Calumet filed a motion to join Exxon as plaintiff in the
subject lawsuit, which was granted July 29, 1994. In August 1994, the Hughes
Group amended its counterclaim to add Calumet as a counter-defendant. Exxon and
Calumet filed a motion to dismiss the counterclaims. On March 22, 1996, the
Court granted Exxon's and Calumet's motion to dismiss the counterclaims alleging
fraud, conspiracy, and federal and Florida RICO violations and challenging the
validity of certain of our oil and natural gas leases but denied such motion as
to the counterclaim alleging conversion of funds. Effective January 1, 2000,
Calumet settled all of the Hughes claims against Calumet with a payment to the
Hughes group of the total sum of $100,000. The remaining defendants filed a writ
seeking to stay the trial but no relief was granted prior to the trial date.
Trial was held on June 19, 2000. By final judgment dated August 18, 2000, the
court dismissed all claims by the Hughes group and the remaining defendants
against Calumet. The remaining defendants have appealed the judgment.
We, in the ordinary course of business, are a claimant and/or a defendant in
various other legal proceedings. Management does not believe that the outcome of
these other legal proceedings, individually and in the aggregate, will have a
materially adverse effect on our financial condition or results of operations.
ITEMS 2, 3, 4 & 5 ARE NOT APPLICABLE AND HAVE BEEN OMITTED
Item 6 - Exhibits and Reports on Form 8-K
A. Exhibits
10.1 Seventh Amendment to Fourth Amended and Restated Credit Agreement,
dated as of October 11, 2000 by and among Plains Resources Inc., First
Union National Bank as Agent and the Lenders named therein.
27.1 Financial Data Schedule
B. Reports on Form 8-K
A Current Report on Form 8-K was filed on September 15, 2000, in connection
with the announcement that Plains All American Pipeline, L.P. and Plains
Resources Inc. had agreed in principle for the settlement of class action
securities suits related to the unauthorized trading losses disclosed in
November 1999.
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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 14, 2000 By: /s/ Cynthia A. Feeback
----------------------
Cynthia A. Feeback, Vice President -
Accounting and Assistant Treasurer
(Principal Accounting Officer)
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