<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 JUNE 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
--- ---
17,931,835 shares of common stock $0.10 par value, issued and outstanding at
August 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:
June 30, 2000 and December 31, 1999......................... 3
Consolidated Statements of Operations:
For the three and six months ended June 30, 2000 and 1999... 4
Consolidated Statements of Cash Flows:
For the six months ended June 30, 2000 and 1999............. 5
Notes to Consolidated Financial Statements....................... 6
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS......................... 20
PART II. OTHER INFORMATION....................................... 33
2
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
2000 1999
----------- ------------
(UNAUDITED)
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 12,077 $ 68,228
Accounts receivable and other current assets 341,843 521,948
Inventory 39,174 40,478
Assets held for sale (Note 4) - 141,486
---------- ----------
Total current assets 393,094 772,140
---------- ----------
PROPERTY AND EQUIPMENT
Oil and natural gas properties - full cost method
Subject to amortization 700,654 671,928
Not subject to amortization 54,279 52,031
Crude oil pipeline, gathering and terminal assets 463,511 458,502
Other property and equipment 6,544 7,706
---------- ----------
1,224,988 1,190,167
Less allowance for depreciation, depletion and amortization (419,397) (402,514)
---------- ----------
805,591 787,653
---------- ----------
OTHER ASSETS 98,240 129,767
---------- ----------
$1,296,925 $1,689,560
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and other current liabilities $ 349,471 $ 546,393
Notes payable and other current obligations 3,511 109,880
---------- ----------
Total current liabilities 352,982 656,273
BANK DEBT 15,000 137,300
BANK DEBT OF A SUBSIDIARY 267,250 259,450
SUBORDINATED DEBT 277,731 277,909
OTHER LONG-TERM DEBT 2,044 2,044
OTHER LONG-TERM LIABILITIES AND DEFERRED CREDITS 11,649 21,107
---------- ----------
926,656 1,354,083
---------- ----------
MINORITY INTEREST 172,075 156,045
---------- ----------
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, $1.00 par value,
46,600 shares authorized, issued and outstanding, 23,300 23,300
Common Stock, $0.10 par value, 50,000,000 shares authorized;
issued and outstanding 17,985,684 and 17,924,050 shares at
June 30, 2000 and December 31, 1999, respectively 1,799 1,792
Additional paid-in capital 130,792 130,027
Accumulated deficit (96,352) (114,500)
Treasury stock, at cost, 9,900 shares (158) -
---------- ----------
59,381 40,619
---------- ----------
$1,296,925 $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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------- --------------------------
2000 1999 2000 1999
-------- -------- ---------- ----------
(RESTATED) (RESTATED)
<S> <C> <C> <C> <C>
REVENUES
Oil and natural gas sales $ 37,290 $ 25,189 $ 70,582 $ 46,331
Marketing, transportation, storage
and terminalling revenues 738,542 861,850 1,737,470 1,317,610
Gain on sale of assets (Note 4) - - 48,188 -
Interest and other income 1,775 238 6,589 307
-------- -------- ---------- ----------
777,607 887,277 1,862,829 1,364,248
-------- -------- ---------- ----------
EXPENSES
Production expenses 15,183 12,100 30,678 23,663
Marketing, transportation, storage
and terminalling expenses 706,194 835,741 1,668,960 1,272,306
Unauthorized trading losses
and related expenses (Note 3) - 21,470 - 42,675
General and administrative 10,514 7,655 21,595 11,717
Depreciation, depletion and amortization 10,084 8,275 25,296 15,445
Interest expense 12,943 10,764 28,817 19,517
-------- -------- ---------- ----------
754,918 896,005 1,775,346 1,385,323
-------- -------- ---------- ----------
Income (loss) before income taxes,
minority interest and extraordinary item 22,689 (8,728) 87,483 (21,075)
Minority interest 7,820 (3,939) 37,404 (8,228)
-------- -------- ---------- ----------
Income (loss) before income taxes
and extraordinary item 14,869 (4,789) 50,079 (12,847)
Income tax expense (benefit)
Current 521 - 521 -
Deferred 5,278 (1,673) 19,010 (4,570)
-------- -------- ---------- ----------
Income (loss) before extraordinary item 9,070 (3,116) 30,548 (8,277)
Extraordinary item, net of tax benefit
and minority interest (3,623) - (4,988) -
-------- -------- ---------- ----------
NET INCOME (LOSS) 5,447 (3,116) 25,560 (8,277)
Less: cumulative preferred stock dividends 3,694 2,473 7,412 4,834
-------- -------- ---------- ----------
NET INCOME (LOSS) AVAILABLE
TO COMMON STOCKHOLDERS $ 1,753 $ (5,589) $ 18,148 $ (13,111)
======== ======== ========== ==========
Basic earnings (loss) per share
Income (loss) before extraordinary item $ 0.30 $ (0.33) $ 1.29 $ (0.78)
Extraordinary item (0.20) - (0.28) -
-------- -------- ---------- ----------
Net income (loss) $ 0.10 $ (0.33) $ 1.01 $ (0.78)
======== ======== ========== ==========
Diluted earnings (loss) per share
Income (loss) before extraordinary item $ 0.29 $ (0.33) $ 1.03 $ (0.78)
Extraordinary item (0.20) - (0.17) -
-------- -------- ---------- ----------
Net income (loss) $ 0.09 $ (0.33) $ 0.86 $ (0.78)
======== ======== ========== ==========
</TABLE>
See notes to consolidated financial statements.
4
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
-------------------------
2000 1999
--------- ----------
(RESTATED)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 25,560 $ (8,277)
Items not affecting cash flows from operating activities:
Depreciation, depletion and amortization 25,296 15,445
Gain on sale of assets (Note 4) (48,188) -
Minority interest in income of a subsidiary 30,434 (8,228)
Deferred income taxes 15,820 (4,570)
Other noncash items 10,443 971
Change in assets and liabilities from operating activities:
Accounts receivable and other current assets 149,380 (72,620)
Inventory 1,304 (1,244)
Pipeline linefill (929) (4)
Accounts payable and other current liabilities (205,450) 104,343
--------- ---------
Net cash provided by operating activities 3,670 25,816
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Costs incurred in connection with acquisitions - (141,971)
Payments for crude oil pipeline, gathering and terminal assets (5,009) (4,677)
Payments for acquisition, exploration and development costs (28,548) (50,980)
Payments for additions to other property and assets (1,827) (1,322)
Proceeds from sale of assets (Note 4) 223,859 -
--------- ---------
Net cash provided by (used in) investing activities 188,475 (198,950)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt 530,750 308,021
Proceeds from short-term debt 45,250 24,150
Principal payments of long-term debt (695,900) (127,721)
Principal payments of short-term debt (100,969) (11,900)
Costs incurred in connection with financing arrangements (6,500) (3,637)
Dividends paid (6,043) -
Distributions to unitholders of subisidiary (14,499) (8,413)
Other (385) (852)
--------- ---------
Net cash provided by (used in) financing activities (248,296) 179,648
--------- ---------
Net increase (decrease) in cash and cash equivalents (56,151) 6,514
Cash and cash equivalents, beginning of period 68,228 6,544
--------- ---------
Cash and cash equivalents, end of period $ 12,077 $ 13,058
========= =========
</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 June 30, 2000 and December 31, 1999,
the results of our operations for the three and six months ended June 30, 2000
and 1999, and cash flows for the six months ended June 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. The results for the three and six months
ended June 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 June 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 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. This statement was amended by SFAS No. 137, Accounting for
Derivative Instruments and Hedging Activities - Deferral of the Effective Date
of FASB Statement No. 133 ("SFAS 137") issued in June 1999. SFAS 137 deferred
the effective date of SFAS 133 to fiscal years beginning after June 15, 2000. We
are required to adopt this statement beginning January 1, 2001. We have not yet
determined what impact the adoption of SFAS 133 would have on the consolidated
balance sheets, statements of operations and cash flows; however, this standard
could increase volatility in earnings and retained earnings (deficit) through
comprehensive income. In June 2000, the FASB issued SFAS 138, "Accounting for
Certain Derivative Instruments and Certain Hedge Activities." SFAS 138 amended
the portions of SFAS 133, inclusive of the definition of the normal purchase and
sale exclusion.
NOTE 2 - INVENTORY AND OTHER ASSETS
Inventory consists of the following (in thousands):
JUNE 30, DECEMBER 31,
2000 1999
------- ------------
Crude oil $34,185 $35,664
Materials and supplies 4,989 4,814
------- -------
$39,174 $40,478
======= =======
6
<PAGE>
Other assets consist of the following (in thousands):
JUNE 30, DECEMBER 31,
2000 1999
-------- -----------
Pipeline linefill $18,562 $ 17,633
Deferred tax asset 51,739 67,366
Land 8,853 8,853
Debt issue costs, net 12,758 26,530
Other, net 6,328 9,385
------- --------
$98,240 $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). 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.
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.
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 Notes 5 and 6). The cost of the pipeline
segment is included in assets held for sale on the consolidated balance sheet at
December 31, 1999.
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 up to $114.0 million plus accrued interest of subordinated debt, and
. provide additional flexibility for working capital, capital expenditures, and
for other general corporate purposes.
7
<PAGE>
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.
. 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 June 30, 2000,
approximately $129.4 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 June 30, 2000, the carrying value of all variable rate bank debt of $285.3
million approximated the fair value at that date. The carrying value and fair
value of redeemable preferred stock were $138.8 million and $168.4 million,
respectively, at June 30, 2000. The carrying value and fair value of the fixed
rate debt was $277.5 million and $274.8 million, respectively, at that date. At
December 31, 1999, the carrying value of all variable rate bank debt and
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 subordinated debt.
NOTE 6 -- EXTRAORDINARY ITEM
During the three and six months ended June 30, 2000, we recognized
extraordinary losses, consisting primarily of unamortized debt issue costs, of
$3.6 million (net of minority interest of $5.1 million and deferred tax of $2.3
million) and $5.0 million (net of minority interest of $7.0 million and deferred
tax of $3.2 million), respectively, related to PAA's early extinguishment of
debt and refinancing of its credit agreements (see Notes 4 and 5).
NOTE 7 -- TREASURY STOCK
In June 2000, our Board of Directors authorized the repurchase of up to one
million shares of our common stock through December 31, 2000. As of June 30,
2000, we had repurchased 9,900 common shares at a cost of $0.2 million. In July
2000, we repurchased an additional 144,300 shares for approximately $2.2
million.
8
<PAGE>
NOTE 8 -- 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 JUNE 30, 2000
Revenues:
External Customers $37,290 $ 738,542 $ 775,832
Intersegment (a) - 425 425
Other income (expense) (1,309) 3,084 1,775
--------- ---------- ----------
Total revenues of reportable segments $35,981 $ 742,051 $ 778,032
========= ========== ==========
Segment gross margin (b) $22,107 $ 32,348 $ 54,455
Segment gross profit (c) 19,588 24,353 43,941
Segment income before income taxes,
minority interest and extraordinary item 6,035 16,654 22,689
------------------------------------------------------------------------------------------
FOR THE THREE MONTHS ENDED JUNE 30, 1999 (RESTATED)
Revenues:
External Customers $25,189 $ 861,850 $ 887,039
Intersegment (a) - 347 347
Other income (expense) 48 190 238
--------- ---------- ----------
Total revenues of reportable segments $25,237 $ 862,387 $ 887,624
========= ========== ==========
Segment gross margin (b) $13,089 $ 4,639 $ 17,728
Segment gross profit (c) 11,217 (1,144) 10,073
Segment income (loss) before income taxes
and minority interest 786 (9,514) (8,728)
------------------------------------------------------------------------------------------
FOR THE SIX MONTHS ENDED JUNE 30, 2000
Revenues:
External Customers $70,582 $1,737,470 $1,808,052
Intersegment (a) - 816 816
Gain on sale of assets - 48,188 48,188
Other income (expense) (4,005) 10,594 6,589
--------- ---------- ----------
Total revenues of reportable segments $66,577 $1,797,068 $1,863,645
========= ========== ==========
Segment gross margin (b) $39,904 $ 68,510 $ 108,414
Segment gross profit (c) 34,955 51,864 86,819
Segment income before income taxes, -
minority interest and extraordinary item 6,804 80,679 87,483
------------------------------------------------------------------------------------------
FOR THE SIX MONTHS ENDED JUNE 30, 1999 (RESTATED)
Revenues:
External Customers $46,331 $1,317,610 $1,363,941
Intersegment (a) - 674 674
Other income (expense) 20 287 307
--------- ---------- ----------
Total revenues of reportable segments $46,351 $1,318,571 $1,364,922
========= ========== ==========
Segment gross margin (b) $22,668 $ 2,629 $ 25,297
Segment gross profit (c) 19,185 (5,605) 13,580
Segment loss before income taxes and
minority interest (1,173) (19,902) (21,075)
------------------------------------------------------------------------------------------
</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
expenses.
c) Gross profit is calculated as revenues less costs of sales and operations
and general and administrative expenses.
9
<PAGE>
NOTE 9 -- 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 six
months ended June 30, 2000 and 1999 (in thousands, except per share amounts):
<TABLE>
<CAPTION>
FOR THE THREE MONTHS ENDED JUNE 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 $ 9,070 $ (3,116)
Less: preferred stock dividends (3,694) (2,473)
------- --------
Income (loss) available to common stockholders 5,376 17,981 $0.30 (5,589) 16,914 $(0.33)
===== ======
Effect of dilutive securities:
Convertible preferred stock - - - -
Employee stock options and warrants - 761 - -
------- ------ --------- -------
Income (loss) available to common
stockholders assuming dilution $ 5,376 18,742 $0.29 $ (5,589) 16,914 $(0.33)
======= ====== ===== ========= ======= ======
FOR THE SIX MONTHS ENDED JUNE 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 $30,548 $ (8,277)
Less: preferred stock dividends (7,412) (4,834)
------- ------
Income (loss) available to common stockholders 23,136 17,964 $1.29 (13,111) 16,902 $(0.78)
===== ======
Effect of dilutive securities:
Convertible preferred stock 7,412 10,935 - -
Employee stock options and warrants - 715 - -
------- ------ ------ ------
Income (loss) available to common
stockholders assuming dilution $30,548 29,614 $1.03 $(13,111) 16,902 $(0.78)
======= ====== ===== ======== ====== ======
</TABLE>
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 and F preferred
stock are for the period from October 1, 1999 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.
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.
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, et al. The suit alleged
that Plains All American Pipeline, L.P. and certain of the general partner's
officers and directors violated federal securities laws, primarily in connection
with unauthorized trading by a former employee. An additional nineteen cases
were filed in the Southern District of Texas, some of which name the general
partner and us as additional defendants. The court consolidated all subsequently
filed cases under the first filed action described above and appointed two lead
plaintiffs representing two different plaintiff classes: (1) purchasers of our
common stock and options (the "Plains Plaintiffs") and (2) purchasers of PAA's
common units (the "PAA Plaintiffs"). On July 14, 2000, the Plains Plaintiffs
filed a consolidated complaint alleging violations of Rule 10b-5 and Section
20(a) of the Securities Exchange Act of 1934. On the same day, the PAA
Plaintiffs filed a consolidated complaint, naming as additional defendants the
underwriters for the public offering of PAA units. The PAA Plaintiffs'
consolidated complaint alleges that the defendants are 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.
10
<PAGE>
The plaintiffs in the Texas securities litigation seek, among other things,
damages for all losses and damages allegedly sustained by the plaintiffs from
the unauthorized trading loss and defendants' alleged misconduct, and any
additional relief as may be just and proper under the circumstances.
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 responsive pleading or motion on behalf of the defendants is
due 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 Plains All American Pipeline, L.P. and its unitholders by failing
to monitor properly the activities of its employees. The derivative complaints
allege, among other things, that Plains All American Pipeline has been harmed
due to the negligence or breach of fiduciary duties of the officers and
directors that are named in the lawsuits. 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. No responsive pleading or
motion on behalf of the defendants is currently due.
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
securities litigation, 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 or results of operations.
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.
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.
11
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET (unaudited) (in thousands)
JUNE 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 $ 8,638 $ 421 $ 3,018 $ - $ 12,077
Accounts receivable and other 9,352 16,421 316,070 - 341,843
Inventory - 6,841 32,333 - 39,174
--------- --------- -------- -------- ----------
Total current assets 17,990 23,683 351,421 - 393,094
--------- --------- -------- -------- ----------
PROPERTY AND EQUIPMENT 236,382 524,369 464,237 - 1,224,988
Less allowance for depreciation,
depletion and amortization (216,737) (128,770) (18,504) (55,386) (419,397)
--------- --------- -------- -------- ----------
19,645 395,599 445,733 (55,386) 805,591
--------- --------- -------- -------- ----------
INVESTMENTS IN SUBSIDIARIES AND
INTERCOMPANY ADVANCES 301,177 (229,067) (29,155) (42,955) -
OTHER ASSETS 27,905 12,383 57,952 - 98,240
--------- --------- -------- -------- ----------
$ 366,717 $ 202,598 $825,951 $(98,341) $1,296,925
========= ========= ======== ======== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and other current liabilities $ 25,220 $ 39,626 $284,475 $ 150 $ 349,471
Notes payable and other current obligations - 511 3,000 - 3,511
--------- --------- -------- -------- ----------
Total current liabilities 25,220 40,137 287,475 150 352,982
BANK DEBT 15,000 - - - 15,000
BANK DEBT OF A SUBSIDIARY - - 267,250 - 267,250
SUBORDINATED DEBT 277,731 - - - 277,731
OTHER LONG-TERM DEBT - 2,044 - - 2,044
OTHER LONG-TERM LIABILITIES 2,078 - 9,571 - 11,649
--------- --------- -------- -------- ----------
320,029 42,181 564,296 150 926,656
--------- --------- -------- -------- ----------
MINORITY INTEREST (70,036) - 242,019 92 172,075
--------- --------- -------- -------- ----------
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 1,799 78 - (78) 1,799
Additional paid-in capital 130,792 3,950 43,394 (47,344) 130,792
Retained earnings (accumulated deficit) (177,822) 156,389 (23,758) (51,161) (96,352)
Treasury stock, at cost (158) - - - (158)
--------- --------- -------- -------- ----------
(22,089) 160,417 19,636 (98,583) 59,381
--------- --------- -------- -------- ----------
$ 366,717 $ 202,598 $825,951 $(98,341) $1,296,925
========= ========= ======== ======== ==========
</TABLE>
12
<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>
13
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS (unaudited) (in thousands)
THREE MONTHS ENDED JUNE 30, 2000
<TABLE>
<CAPTION>
GUARANTOR NONGUARANTOR INTERCOMPANY
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
-------- ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
REVENUES
Oil and natural gas sales $ - $36,865 $ - $ 425 $ 37,290
Marketing, transportation, storage and
terminalling - - 738,967 (425) 738,542
Interest and other income (expense) (462) 59 3,084 (906) 1,775
-------- ------- -------- ----- --------
(462) 36,924 742,051 (906) 777,607
-------- ------- -------- ----- --------
EXPENSES
Production expenses - 15,183 - - 15,183
Marketing, transportation, storage and
terminalling - - 706,194 - 706,194
General and administrative 560 1,959 7,995 - 10,514
Depreciation, depletion and amortization 861 4,528 4,695 - 10,084
Interest expense 2,338 5,424 6,087 (906) 12,943
-------- ------- -------- ----- --------
3,759 27,094 724,971 (906) 754,918
-------- ------- -------- ----- --------
Income (loss) before income taxes,
minority interest and extraordinary item (4,221) 9,830 17,080 - 22,689
Minority interest - - 7,820 - 7,820
-------- ------- -------- ----- --------
Income (loss) before income taxes (4,221) 9,830 9,260 - 14,869
Income tax expense (benefit):
Current 185 104 232 - 521
Deferred 8,161 2,236 (5,119) - 5,278
-------- ------- -------- ----- --------
Income (loss) before extraordinary item (12,567) 7,490 14,147 - 9,070
Extraordinary item, net of tax benefit
and minority interest - - (3,623) - (3,623)
-------- ------- -------- ----- --------
NET INCOME (LOSS) (12,567) 7,490 10,524 - 5,447
Less: cumulative preferred stock dividends 3,694 - - - 3,694
-------- ------- -------- ----- --------
NET INCOME (LOSS) AVAILABLE
TO COMMON STOCKHOLDERS $(16,261) $ 7,490 $ 10,524 $ - $ 1,753
======== ======= ======== ===== ========
</TABLE>
14
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS (unaudited) (in thousands) (restated)
THREE MONTHS ENDED JUNE 30, 1999
<TABLE>
<CAPTION>
GUARANTOR NONGUARANTOR INTERCOMPANY
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
-------- ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
REVENUES
Oil and natural gas sales $ - $24,842 $ - $ 347 $ 25,189
Marketing, transportation, storage and
terminalling - - 862,524 (674) 861,850
Interest and other income 36 10 192 - 238
--------------------------------------------------------------------------------------
36 24,852 862,716 (327) 887,277
--------------------------------------------------------------------------------------
EXPENSES
Production expenses - 12,100 - - 12,100
Marketing, transportation, storage and
terminalling - - 836,068 (327) 835,741
Unauthorized trading losses and related expenses - - 21,470 - 21,470
General and administrative 505 1,368 5,782 - 7,655
Depreciation, depletion and amortization 638 3,797 3,840 - 8,275
Interest expense 1,583 4,461 4,720 - 10,764
--------------------------------------------------------------------------------------
2,726 21,726 871,880 (327) 896,005
--------------------------------------------------------------------------------------
Income (loss) before income taxes and
minority interest (2,690) 3,126 (9,164) - (8,728)
Minority interest - - (3,939) - (3,939)
--------------------------------------------------------------------------------------
Income (loss) before income taxes (2,690) 3,126 (5,225) - (4,789)
Income tax expense (benefit)
Current (3,156) - 3,156 - -
Deferred 2,332 1,376 (5,381) - (1,673)
--------------------------------------------------------------------------------------
NET INCOME (LOSS) (1,866) 1,750 (3,000) - (3,116)
Less: cumulative preferred stock dividends 2,473 - - - 2,473
--------------------------------------------------------------------------------------
NET INCOME (LOSS) AVAILABLE
TO COMMON STOCKHOLDERS $(4,339) $ 1,750 $ (3,000) $ - $ (5,589)
======================================================================================
</TABLE>
15
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS (unaudited) (in thousands)
SIX MONTHS ENDED JUNE 30, 2000
<TABLE>
<CAPTION>
GUARANTOR NONGUARANTOR INTERCOMPANY
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
-------- ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
REVENUES
Oil and natural gas sales $ - $69,766 $ - $ 816 $ 70,582
Marketing, transportation, storage and
terminalling - - 1,738,286 (816) 1,737,470
Gain on sale of assets - - 48,188 - 48,188
Interest and other income (expense) (1,044) 101 10,594 (3,062) 6,589
---------------------------------------------------------------------------------------
(1,044) 69,867 1,797,068 (3,062) 1,862,829
---------------------------------------------------------------------------------------
EXPENSES
Production expenses - 30,678 - - 30,678
Marketing, transportation, storage and
terminalling - - 1,668,960 - 1,668,960
General and administrative 1,062 3,887 16,646 - 21,595
Depreciation, depletion and amortization 1,675 8,754 14,867 - 25,296
Interest expense 6,155 10,624 15,100 (3,062) 28,817
---------------------------------------------------------------------------------------
8,892 53,943 1,715,573 (3,062) 1,775,346
---------------------------------------------------------------------------------------
Income (loss) before income taxes,
minority interest and extraordinary item (9,936) 15,924 81,495 - 87,483
Minority interest - - 37,404 - 37,404
---------------------------------------------------------------------------------------
Income (loss) before income taxes (9,936) 15,924 44,091 - 50,079
Income tax expense (benefit):
Current 185 104 232 - 521
Deferred 6,732 3,813 8,465 - 19,010
---------------------------------------------------------------------------------------
Income (loss) before extraordinary item (16,853) 12,007 35,394 - 30,548
Extraordinary item, net of tax benefit
and minority interest - - (4,988) - (4,988)
---------------------------------------------------------------------------------------
NET INCOME (LOSS) (16,853) 12,007 30,406 - 25,560
Less: cumulative preferred stock dividends 7,412 - - - 7,412
---------------------------------------------------------------------------------------
NET INCOME (LOSS) AVAILABLE
TO COMMON STOCKHOLDERS $(24,265) $12,007 $ 30,406 $ - $ 18,148
=======================================================================================
</TABLE>
16
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS (unaudited) (in thousands) (restated)
SIX MONTHS ENDED JUNE 30, 1999
<TABLE>
<CAPTION>
GUARANTOR NONGUARANTOR INTERCOMPANY
PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED
-------- ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
REVENUES
Oil and natural gas sales $ - $45,657 $ - $ 674 $ 46,331
Marketing, transportation, storage and
terminalling - - 1,318,284 (674) 1,317,610
Interest and other income (expense) (3) 22 288 - 307
-------------------------------------------------------------------------------
(3) 45,679 1,318,572 - 1,364,248
-------------------------------------------------------------------------------
EXPENSES
Production expenses - 23,663 - - 23,663
Marketing, transportation, storage and
terminalling - - 1,272,306 - 1,272,306
Unauthorized trading losses and related
expenses - - 42,675 - 42,675
General and administrative 888 2,596 8,233 - 11,717
Depreciation, depletion and amortization 1,260 7,514 6,671 - 15,445
Interest expense 2,613 8,991 7,913 - 19,517
------------------------------------------------------------------------------
4,761 42,764 1,337,798 - 1,385,323
------------------------------------------------------------------------------
Income (loss) before income taxes and
minority interest (4,764) 2,915 (19,226) - (21,075)
Minority interest - - (8,228) - (8,228)
------------------------------------------------------------------------------
Income (loss) before income taxes (4,764) 2,915 (10,998) - (12,847)
Income tax expense (benefit)
Current (3,156) - 3,156 - -
Deferred 3,012 50 (7,632) - (4,570)
------------------------------------------------------------------------------
NET INCOME (LOSS) (4,620) 2,865 (6,522) - (8,277)
Less: cumulative preferred stock
dividends 4,834 - - - 4,834
-------------------------------------------------------------------------------
NET INCOME (LOSS) AVAILABLE
TO COMMON STOCKHOLDERS $(9,454) $ 2,865 $ (6,522) $ - $ (13,111)
===============================================================================
</TABLE>
17
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (unaudited) (in thousands)
SIX MONTHS ENDED JUNE 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) $ (16,853) $ 12,007 $ 30,406 $ - $ 25,560
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation, depletion, and amortization 1,675 8,754 14,867 - 25,296
Gain on sale of assets (Note 4) - - (48,188) - (48,188)
Minority interest in income of a subsidiary - - 30,434 - 30,434
Deferred income tax 6,732 3,813 5,275 - 15,820
Other noncash items 5,731 - 4,712 - 10,443
Change in assets and liabilities resulting from
operating activities:
Accounts receivable and other (7,544) (5,201) 162,125 - 149,380
Inventory - (1,189) 2,493 - 1,304
Pipeline linefill - - (929) - (929)
Accounts payable and other current liabilities 1,520 637 (207,607) - (205,450)
--------------------------------------------------------------------------
NET CASH FLOWS PROVIDED BY
(USED IN) OPERATING ACTIVITIES (8,739) 18,821 (6,412) - 3,670
--------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Payments for crude oil pipeline, gathering
and terminal assets - - (5,009) - (5,009)
Payments for acquisition, exploration,
and development costs (1,108) (27,440) - - (28,548)
Payments for additions to other property and
assets (117) (1,173) (537) - (1,827)
Proceeds from sale of assets (Note 4) - - 223,859 - 223,859
--------------------------------------------------------------------------
NET CASH PROVIDED BY
(USED IN) INVESTING ACTIVITIES (1,225) (28,613) 218,313 - 188,475
--------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Advances/investments with affiliates 125,615 5,079 (130,694) - -
Proceeds from long-term debt 87,700 - 443,050 - 530,750
Proceeds from short-term debt - - 45,250 - 45,250
Principal payments of long-term debt (210,000) - (485,900) - (695,900)
Principal payments of short-term debt - - (100,969) - (100,969)
Costs incurred in connection with financing
arrangements - - (6,500) (6,500)
Dividends paid (6,043) - - (6,043)
Distribution to unitholders 12,474 - (26,973) - (14,499)
Other (385) - - (385)
--------------------------------------------------------------------------
NET CASH PROVIDED BY
(USED IN) FINANCING ACTIVITIES 9,361 5,079 (262,736) - (248,296)
--------------------------------------------------------------------------
Net decrease in cash and cash equivalents (603) (4,713) (50,835) - (56,151)
Cash and cash equivalents, beginning of period 9,241 5,134 53,853 - 68,228
--------------------------------------------------------------------------
Cash and cash equivalents, end of period $ 8,638 $ 421 $ 3,018 $ - $ 12,077
==========================================================================
</TABLE>
18
<PAGE>
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (unaudited) (in thousands)
(restated)
SIX MONTHS ENDED JUNE 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) $ (4,620) $ 2,865 $ (6,522) $ - $ (8,277)
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation, depletion, and amortization 1,260 7,514 6,671 - 15,445
Minority interest in income of a subsidiary - - (8,228) - (8,228)
Deferred income tax 3,012 50 (7,632) - (4,570)
Other noncash items 789 - 182 - 971
Change in assets and liabilities resulting from
operating activities:
Accounts receivable and other (1,168) 2,370 (73,822) - (72,620)
Inventory - 6 (1,250) - (1,244)
Pipeline linefill - - (4) - (4)
Accounts payable and other current liabilities (2,987) 5,870 102,908 (1,448) 104,343
-------- -------- --------- ------- ---------
NET CASH FLOWS PROVIDED BY
(USED IN) OPERATING ACTIVITIES (3,714) 18,675 12,303 (1,448) 25,816
-------- -------- --------- ------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Payment for acquisition of midstream assets - - (141,971) - (141,971)
Payments for crude oil pipeline, gathering
and terminal assets - - (4,677) - (4,677)
Payments for acquisition, exploration,
and development costs (3,021) (47,959) - - (50,980)
Payments for additions to other property and assets (90) (1,074) (158) - (1,322)
-------- -------- --------- ------- ---------
NET CASH USED IN INVESTING ACTIVITIES (3,111) (49,033) (146,806) - (198,950)
-------- -------- --------- ------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Advances/investments with affiliates (42,018) 30,454 11,564 - -
(Payment) proceeds from issuance of Class B
Common Units (25,000) - 25,000 - -
Proceeds from long-term debt 120,400 - 187,621 - 308,021
Proceeds from short-term debt - - 24,150 - 24,150
Principal payments of long-term debt (55,100) - (72,621) - (127,721)
Principal payments of short-term debt - - (11,900) - (11,900)
Costs incurred in connection with financing
arrangements (110) - (3,527) (3,637)
Distribution to unitholders 11,328 - (19,741) - (8,413)
Other (852) - - - (852)
-------- -------- --------- ------- ---------
NET CASH PROVIDED BY FINANCING ACTIVITIES 8,648 30,454 140,546 - 179,648
-------- -------- --------- ------- ---------
Net increase (decrease) in cash and cash
equivalents 1,823 96 6,043 (1,448) 6,514
Cash and cash equivalents, beginning of period 142 194 6,408 (200) 6,544
-------- -------- --------- ------- ---------
Cash and cash equivalents, end of period $ 1,965 $ 290 $ 12,451 $(1,648) $ 13,058
======== ======== ========= ======= =========
</TABLE>
19
<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). Approximately $154.9 million of the unauthorized trading loss was
recognized in 1999, with approximately $21.2 million and $21.5 million of this
amount recognized in the first and second quarters of 1999, respectively. As a
result, we have previously restated our 1999 financial information.
RESULTS OF OPERATIONS
Three Months Ended June 30, 2000 and 1999
For the three months ended June 30, 2000, we reported net income of $5.4
million, or $0.10 per basic share ($0.09 per diluted share) on total revenue of
$777.6 million, as compared with a net loss of $3.1 million, or $0.33 per basic
and diluted share on total revenue of $887.3 million in the second quarter of
1999. Results for the three months ended June 30, 2000 and 1999 include the
following unusual or nonrecurring items:
2000
. $1.3 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) and
. an extraordinary loss of $3.6 million related to the early extinguishment of
debt (net of minority interest and tax benefit).
1999
. $21.5 million of unauthorized trading losses.
Excluding nonrecurring items, we would have reported net income of
approximately $9.1 million and $4.6 million for the three months ended June 30,
2000 and 1999, respectively. Adjusted EBITDA increased 40% in 2000 to $44.4
million from the $31.8 million reported in the second 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 $24.7 million and $16.3 million for the second 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 $37.3 million for
the second quarter of 2000, an approximate 48% increase from the 1999 second
quarter amount of $25.2 million due to higher product prices and increased
production volumes which contributed approximately $7.5 million and $4.6 million
to the increase, respectively.
Marketing, transportation, storage and terminalling revenues. Marketing,
transportation, storage and terminalling revenues decreased to $738.5 million
for the second quarter of 2000 compared to the 1999 second quarter amount of
$861.9 million, as lower current year lease gathering and bulk purchase volumes
and decreased pipeline margin revenues offset higher crude oil prices.
20
<PAGE>
Production expenses. Total production expenses increased to $15.2 million from
$12.1 million in the second quarter of 1999 primarily due to increased
production volumes resulting from our acquisition and exploitation activities
and increased per unit costs.
Marketing, transportation, storage and terminalling expenses. Marketing,
transportation, storage and terminalling expenses decreased to $706.2 million in
the second quarter of 2000 compared to $835.7 million 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 offset by
increased purchase costs as a result of higher crude oil prices.
General and administrative. General and administrative expenses were $10.5
million for the second quarter of 2000 compared to $7.7 million for the second
quarter of 1999. Our upstream and midstream activities accounted for
approximately $0.6 million and $2.2 million, respectively, of the increase.
Depreciation, depletion and amortization. Primarily as a result of our mid-
1999 midstream acquisitions and increased upstream production levels, total
depreciation, depletion and amortization expense ("DD&A") for the second quarter
of 2000 was $10.1 million as compared to $8.3 million for the second quarter of
1999.
Interest expense. Interest expense for the second quarter of 2000 was $12.9
million, an increase of $2.2 million over last year's second quarter. The
increase is primarily due to higher interest rates in 2000 as compared to 1999.
Nonrecurring items
Early extinguishment of debt. During the quarter ended June 30, 2000, we
recognized an extraordinary loss, consisting primarily of unamortized debt
issue costs, totaling $3.6 million (net of minority interest of $5.1 million
and deferred tax of $2.3 million) related to the refinancing of PAA's credit
facilities. In addition, interest and other income includes $1.3 million of net
deferred gains from terminated interest rate swaps as a result of the debt
extinguishment.
Unauthorized trading losses. As previously discussed, we recognized losses of
approximately $21.5 million in the second quarter of 1999 as a result of
unauthorized trading by a former employee of PAA.
Upstream Results
The following table reflects certain of our upstream operating information for
the periods presented:
<TABLE>
<CAPTION>
THREE MONTHS ENDED
JUNE 30,
---------------------------
2000 1999
------------ ------------
<S> <C> <C>
AVERAGE DAILY PRODUCTION VOLUMES (in thousands):
Barrels of oil equivalent ("BOE")
California onshore (approximately 91% oil) 15.1 15.7
Offshore California (100% oil) 4.5 -
Gulf Coast (100% oil) 2.6 2.5
Illinois Basin (100% oil) 2.9 3.0
---------- ----------
Total (approximately 95% oil) 25.1 21.2
========== ==========
UNIT ECONOMICS:
Average sales price per BOE $16.35 $13.05
Production expense per BOE 6.65 6.27
---------- ----------
Gross margin per BOE 9.70 6.78
Upstream G&A expense per BOE 1.10 0.97
---------- ----------
Gross profit per BOE $ 8.60 $ 5.81
========== ==========
</TABLE>
Total oil equivalent production increased approximately 18% to an average of
25,100 BOE per day as compared to the second quarter 1999 average of 21,200 BOE
per day. The increase is primarily attributable to the offshore California Point
Arguello Unit, which we acquired from Chevron in July 1999. Net daily production
from our onshore California properties averaged 15,100 barrels per day in the
second quarter of
21
<PAGE>
2000 compared to 15,700 barrels per day in the prior year period. Net daily
production for our Gulf Coast properties averaged approximately 2,600 barrels
per day during the second quarter of 2000, compared to 2,500 barrels per day in
the prior year period. Net daily production in the Illinois Basin averaged
approximately 2,900 barrels per day during the second quarter of 2000, a
decrease of approximately 3% compared to 3,000 barrels per day during the second
quarter of 1999, due primarily to natural decline.
Our average product price was $16.35 per BOE, up 25% as compared to the 1999
second quarter average wellhead price of $13.05 per BOE. Our product price
represents a combination of fixed-price and floating-price sales arrangements
tied to a benchmark price index and subjected to discounts for location and
quality differentials. The price index is the NYMEX benchmark WTI crude oil
price, which averaged $28.69 per barrel during the second quarter of 2000,
approximately 63% above the $17.65 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 $7.53 and $0.12
per BOE in the second quarter of 2000 and 1999, respectively. We maintained
hedges on approximately 78% and 65% of our crude oil production in the second
quarter of 2000 and 1999, respectively.
Upstream unit gross margin (well-head revenue less production expenses) for
the second quarter of 2000 was $9.70 per BOE, a 43% increase as compared to
$6.78 per BOE reported for the second quarter of 1999. Average unit production
expenses averaged $6.65 per BOE for the second quarter of 2000, an approximate
6% increase over the 1999 second quarter average of $6.27 per BOE. The increase
is due to higher chemical costs for our Illinois properties as well as higher
costs related to equipment failures in Florida. Expenses related to equipment
failures in Florida were lower than average in the prior year period as we
experienced a lower than average equipment failure rate. In addition, 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.
Unit general and administrative expenses increased to $1.10 per BOE in the
second quarter of 2000, compared to $0.97 per BOE in the prior year comparative
quarter. Total upstream general and administrative expense was $2.5 million
during the second quarter of 2000 compared to $1.9 million in the second quarter
of 1999. The increase is primarily attributable to increased overhead expenses
related to our production and corporate activities.
Total upstream DD&A was $5.4 million in the second quarter of 2000 compared to
$4.4 million in the second quarter of 1999. The increase is 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 second quarter of 2000 compared to $2.10 in
the 1999 comparative quarter.
Midstream Results
Gross margin from our midstream activities was $32.3 million in the second
quarter compared to $4.6 million ($26.1 million excluding the unauthorized
trading losses) in the second 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
JUNE 30,
--------------------------------
2000 1999
------------- -------------
(RESTATED)
<S> <C> <C>
OPERATING RESULTS:
Gross margin:
Pipeline $12,759 $ 12,917
Gathering and marketing and
terminalling and storage 19,589 13,192
Unauthorized trading losses - (21,470)
------------- -------------
Total 32,348 4,639
General and administrative expense (7,995) (5,783)
------------- -------------
Gross profit $24,353 $ (1,144)
============= =============
</TABLE>
Table continued on following page
22
<PAGE>
<TABLE>
<CAPTION>
THREE MONTHS ENDED
JUNE 30,
--------------------------
2000 1999
----------- -----------
<S> <C> <C>
Average Daily Volumes (MBbls/day):
Pipeline Activities:
All American
Tariff activities 74 101
Margin activities 57 63
Other 118 20
----------- -----------
Total 249 184
=========== ===========
Lease gathering 208 227
Bulk purchases 26 137
----------- -----------
Total 234 364
=========== ===========
Terminal throughput 61 84
=========== ===========
Storage leased to third parties,
monthly average volumes 1,953 2,333
=========== ===========
</TABLE>
Pipeline Operations. Gross margin from pipeline operations was $12.8 million
for the quarter ended June 30, 2000 compared to $12.9 million for the prior year
quarter. Increased margins from the Scurlock and West Texas gathering system
acquisitions in mid-1999 were offset by a decrease in tariff transport volumes.
These volumes decreased due to the sale of the segment of the All American
Pipeline and lower production from Exxon's Santa Ynez Field and the Point
Arguello Field, both offshore California.
Gross revenues from pipeline margin activities decreased approximately $119.0
million from the prior year period primarily due to the sale of the segment of
the All American Pipeline and a decrease in volumes that were purchased and
resold. The margin between revenue and direct cost of crude purchased was $3.9
million for the quarter ended June 30, 2000 compared to $8.9 million for the
prior year second quarter. Pipeline tariff revenues were approximately $12.8
million for the second quarter of 2000 compared to approximately $10.5 million
for the same period in 1999 as increases related to the Scurlock and West Texas
gathering system acquisitions were offset by the sale of the All American
Pipeline segment. Pipeline operations and maintenance expenses decreased to $3.9
million for the second quarter of 2000 compared to $6.8 million for the second
quarter of 1999, also due to the acquisitions and disposition.
Tariff transport volumes on the All American Pipeline decreased from an
average of 101,000 barrels per day for the quarter ended June 30, 1999 to 74,000
barrels per day in the comparable quarter of 2000, primarily due the sale of the
California to Texas portion of the line and to a decrease in shipments of
offshore California production, which decreased from 79,000 barrels per day to
74,000 barrels per day. Barrels associated with our merchant activities on the
All American Pipeline decreased from 63,000 barrels per day in the second
quarter of 1999 to 57,000 barrels per day in the second quarter of 2000, also
due to the sale of the line. Tariff volumes shipped on the Scurlock and West
Texas gathering systems averaged 118,000 barrels per day and 20,000 barrels per
day during the second quarter of 2000 and 1999, respectively. The 1999 period
includes volumes for Scurlock effective May 1, 1999, and no volumes for the West
Texas gathering system which was acquired effective July 1, 1999.
Gathering and Marketing Activities and Terminalling and Storage Activities.
Gross margin from gathering, marketing, terminalling and storage activities was
approximately $19.6 million for the quarter ended June 30, 2000 compared to
$13.2 million in the prior year quarter (excluding the unauthorized trading
losses), primarily due to an increase in our per barrel margin from $0.54 in the
prior year period to $0.80 per barrel in the current year period. Gross revenues
from these activities were approximately $632.0 million and $639.1 million in
the second quarter of 2000 and 1999, respectively, as decreased revenues
primarily due to lower bulk purchase volumes offset increased revenues resulting
from higher crude oil prices. Our average sales price was approximately $26.14
per barrel in the current year period compared to $17.96 per barrel in the prior
year period.
Lease gathering volumes decreased from an average of 227,000 barrels per day
in the second quarter of 1999 to approximately 208,000 barrels per day in the
current year period. Bulk purchase volumes decreased from approximately 137,000
barrels per day in the 1999 second quarter to approximately 26,000 barrels per
day in the current year period. These decreases are primarily due to the
termination of low-margin purchase contracts subsequent to the discovery of the
unauthorized trading losses.
23
<PAGE>
In the period immediately following the disclosure of the unauthorized trading
losses, a significant number of our suppliers and trading partners reduced or
eliminated the open credit previously extended to us. Consequently, the amount
of letters of credit we needed to support the level of our crude oil purchases
then in effect increased significantly. In addition, the cost of obtaining
letters of credit increased under our amended credit facility. In many
instances we arranged for letters of credit to secure our obligations to
purchase crude oil from our customers, which increased our letter of credit
costs and decreased our unit margins. In other instances, primarily involving
lower-margin wellhead and bulk purchases, our purchase contracts were
terminated.
Midstream general and administrative expenses were $8.0 million for the
quarter ended June 30, 2000 compared to $5.8 million for the second quarter in
1999. The increase in 2000 is primarily due to the Scurlock acquisition for
which only two months of operations are included in the 1999 quarter
(approximately $1.7 million) and consulting fees related to assistance in review
and implementation of enhanced controls.
Midstream depreciation and amortization expense was $4.7 million for the
quarter ended June 30, 2000, compared to $3.8 million for the second quarter of
1999. The increase is primarily due to the Scurlock and West Texas gathering
system acquisitions in mid-1999 and increased amortization of debt issue costs.
These increases were partially offset by decreased depreciation related to the
segment of the All American Pipeline that was sold.
Six Months Ended June 30, 2000 and 1999
For the six months ended June 30, 2000, we reported net income of $25.6
million, or $1.01 per basic share ($0.86 per diluted share) on total revenue of
$1.9 billion, as compared with a net loss of $8.3 million, or $0.78 per basic
and diluted share on total revenue of $1.4 billion in the first half of 1999.
Results for the six months ended June 30, 2000 and 1999 include the following
unusual 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;
. $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);
. $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;
. an extraordinary loss of $5.0 million related to the early extinguishment of
debt (net of minority interest and tax benefit), and
. amortization of $4.6 million of debt issue costs associated with facilities
put in place during the fourth quarter of 1999.
1999
. $42.7 million of unauthorized trading losses and
. restructuring expenses of $0.4 million.
Excluding nonrecurring items, we would have reported net income of
approximately $15.7 million and $7.1 million for the six months ended June 30,
2000 and 1999, respectively. Adjusted EBITDA increased 56% in 2000 to $88.2
million from the $56.5 million reported in the first half of 1999. Cash flow
from operations after deducting minority interest (net income before noncash
items) was $48.5 million and $28.1 million in the first half 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 $70.6 million for
the first half of 2000, an approximate 52% increase from the 1999 first half
amount of $46.3 million due to higher product prices and increased production
volumes which contributed approximately $17.0 million and $7.3 million to the
increase, respectively.
Marketing, transportation, storage and terminalling revenues. Marketing,
transportation, storage and terminalling revenues increased to $1,737.5 million
for the first half of 2000 from the 1999 amount of $1,317.6 million. The
increase is primarily due to higher crude oil prices, which were partially
offset by lower current year volumes.
24
<PAGE>
Production expenses. Total production expenses increased to $30.7 million from
$23.7 million in the first half of 2000 and 1999, respectively, primarily due to
increased production volumes resulting from our acquisition and exploitation
activities and increased per unit costs.
Marketing, transportation, storage and terminalling expenses. Marketing,
transportation, storage and terminalling expenses increased to $1,668.9 million
in the first half of 2000 compared to $1,272.3 million in the same period in
1999. The increase is primarily due higher crude oil prices, which partially
offset lower current year volumes.
General and administrative. General and administrative expenses were $21.6
million for the first half of 2000 compared to $11.7 million for the first half
of 1999. Our upstream and midstream activities accounted for approximately $1.5
million and $8.4 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 half of 2000 was $25.3
million as compared to $15.4 million for the first half of 1999.
Interest expense. Interest expense for the first half of 2000 was $28.8
million, an increase of $9.3 million over the first six 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 $2.1 million
and $2.2 million for the six months ended June 30, 2000 and 1999, respectively.
Nonrecurring items
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 six months ended June 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 six months ended June
30, 2000 includes $4.4 million of net deferred gains from terminated interest
rate swaps as a result of the debt extinguishments.
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.
Unauthorized trading losses. As previously discussed, we recognized losses of
approximately $42.7 million in the first half of 1999 as a result of
unauthorized trading by a former employee.
Restructuring charge. A $0.4 million restructuring charge, primarily
associated with personnel reduction was incurred by PAA in the first quarter of
1999. Approximately $0.1 million is included in marketing, transportation,
storage and terminalling expenses and approximately $0.3 million is included in
general and administrative expenses.
25
<PAGE>
Upstream Results
The following table reflects certain of our upstream operating information for
the periods presented:
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
------------------------------
2000 1999
------------ ------------
<S> <C> <C>
AVERAGE DAILY PRODUCTION VOLUMES (in thousands):
Barrels of oil equivalent
California onshore (approximately 91% oil) 14.9 15.3
Offshore California (100% oil) 4.3 -
Gulf Coast (100% oil) 2.2 2.7
Illinois Basin (100% oil) 2.8 3.1
------------ ------------
Total (approximately 95% oil) 24.2 21.1
============ ============
UNIT ECONOMICS:
Average sales price per BOE $15.99 $12.14
Production expense per BOE 6.95 6.20
------------ ------------
Gross margin per BOE 9.04 5.94
Upstream G&A expense per BOE 1.12 0.91
------------ ------------
Gross profit per BOE $ 7.92 $ 5.03
============ ============
</TABLE>
Total oil equivalent production increased approximately 15% to an average of
24,200 BOE per day as compared to the first half 1999 average of 21,100 BOE per
day. The increase is primarily attributable to the offshore California Point
Arguello Unit, which we acquired from Chevron in July 1999. Net daily production
from our onshore California properties averaged 14,900 barrels per day in the
first half of 2000 compared to 15,300 barrels per day in the prior period. Net
daily production for our Gulf Coast properties averaged approximately 2,200
barrels per day during the first half 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 half of 2000, a decrease of approximately 10% compared to 3,100
barrels per day during the first half of 1999, due primarily to natural decline.
Our average product price was $15.99 per BOE, up 32% as compared to the 1999
first half average wellhead price of $12.14 per BOE. Our product price
represents a combination of fixed-price and floating-price sales arrangements
tied to a benchmark price index and subjected to discounts for location and
quality differentials. The price index is the NYMEX benchmark WTI crude oil
price, which averaged $28.73 per barrel during the first half of 2000,
approximately 87% above the $15.35 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 $7.82 per BOE in
the first half of 2000 and increasing our average price by $1.03 per BOE in the
first half of 1999. We maintained hedges on approximately 81% and 56% of our
crude oil production in the first half of 2000 and 1999, respectively.
Upstream unit gross margin (well-head revenue less production expenses) for
the first half of 2000 was $9.04 per BOE, a 52% increase as compared to $5.94
per BOE reported for the first half of 1999. Average unit production expenses
averaged $6.95 per BOE for the first half of 2000, an approximate 12% increase
over the 1999 first half average of $6.20 per BOE. The increase is due to higher
chemical costs for our Illinois properties as well as higher costs related to
equipment failures in Florida. Expenses related to equipment failures in Florida
were lower than average in the prior year period as we experienced a lower than
average equipment failure rate. In addition, 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.
Unit general and administrative expenses increased to $1.12 per BOE in the
first half of 2000, compared to $0.91 per BOE in the prior year comparative
period. Total upstream general and administrative expense was $4.9 million
during the first half of 2000 compared to $3.5 million in the first half of
1999. The increase is primarily attributable to increased overhead costs related
to our production and corporate activities and to increased legal and consulting
fees.
Total upstream DD&A was $10.4 million in the first half of 2000 compared to
$8.8 million in the first half 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 half of 2000 compared to $2.10
in the 1999 comparative period.
26
<PAGE>
Midstream Results
Gross margin from our midstream activities was $68.5 million in the first half
of 2000 compared to $2.6 million ($45.3 million excluding the unauthorized
trading losses) in the first half 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>
SIX MONTHS ENDED
JUNE 30,
-----------------------------
2000 1999
------------ ------------
(RESTATED)
<S> <C> <C>
OPERATING RESULTS:
Gross margin:
Pipeline $ 25,914 $ 24,799
Gathering and marketing and
terminalling and storage 42,596 20,505
Unauthorized trading losses - (42,675)
------------ ------------
Total 68,510 2,629
General and administrative expense (16,646) (8,234)
------------ ------------
Gross profit $ 51,864 $ (5,605)
============ ============
AVERAGE DAILY VOLUMES (MBBLS/DAY):
Pipeline Activities:
All American
Tariff activities 73 113
Margin activities 58 55
Other 116 10
------------ ------------
Total 247 178
============ ============
Lease gathering 218 164
Bulk purchases 28 116
------------ ------------
Total 246 280
============ ============
Terminal throughput 55 79
============ ============
Storage leased to third parties,
monthly average volumes 1,389 2,026
============ ============
</TABLE>
Pipeline Operations. Gross margin from pipeline operations was $25.9 million
for the six months ended June 30, 2000 compared to $24.9 million for the prior
year period. Increased margins from the Scurlock and West Texas gathering system
acquisitions in mid-1999, were offset by lower revenues due to a decrease in
tariff transport volumes. These 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 and a decrease in
volumes that were purchased and resold.
Gross revenues from pipeline margin activities decreased approximately $92.0
million from the prior year period primarily due to the sale of the segment of
the All American Pipeline and a decrease in volumes that were purchased and
resold. The margin between revenue and direct cost of crude purchased was $9.2
million for the six months ended June 30, 2000 compared to $14.0 million for the
prior year first half. Pipeline tariff revenues were approximately $24.3 million
for the first half of 2000 compared to approximately $23.9 million for the same
period in 1999 as increases related to the Scurlock and West Texas gathering
system acquisitions were offset by the sale of the segment of the All American
Pipeline. Pipeline operations and maintenance expenses were approximately $7.6
million for the first half of 2000 compared to $13.0 million for the first half
of 1999, also due to the acquisitions and disposition.
Tariff transport volumes on the All American Pipeline decreased from an
average of 113,000 barrels per day for the six months ended June 30, 1999 to
73,000 barrels per day in the comparable period of 2000, primarily due to the
sale of the California to Texas portion of the line and a decrease in shipments
of offshore California production, which decreased from 83,000 barrels per day
to 73,000 barrels per day. Barrels associated with our merchant activities on
the All American Pipeline increased from 55,000 barrels per day in the first
half of 1999 to 58,000 barrels per day in the same period of 2000. Tariff
volumes shipped on the Scurlock and West Texas gathering systems averaged
116,000 barrels per day and 10,000 barrels per day during the first half of 2000
and 1999, respectively. The 1999 period includes volumes for Scurlock effective
May 1, 1999, and no volumes for the West Texas gathering system which was
acquired effective July 1, 1999.
27
<PAGE>
Gathering and Marketing Activities and Terminalling and Storage Activities.
Gross margin from gathering, marketing, terminalling and storage activities was
approximately $42.6 million for the six months ended June 30, 2000 compared to
$20.5 million in the prior year period (excluding the unauthorized trading
losses). The increase in gross margin is primarily due to an increase in lease
gathering volumes as a result of the Scurlock acquisition and favorable market
conditions in the current year period. Our per barrel margin increased from
$0.48 in the prior year period to $0.87 per barrel in the current year period.
Gross revenues from gathering, marketing, terminalling and storage activities
were approximately $1.4 billion and $0.9 billion in the first half of 2000 and
1999, respectively, as increased revenues resulting from higher crude oil prices
were partially offset by decreased revenues primarily due to lower bulk purchase
volumes. Our average sales price was approximately $28.78 per barrel in the
current year period compared to $16.98 per barrel in the prior year period.
Lease gathering volumes increased from an average of 164,000 barrels per day
for the first half of 1999 to approximately 218,000 barrels per day in 2000.
Bulk purchase volumes decreased from approximately 116,000 barrels per day for
the first half of 1999 to approximately 28,000 barrels per day in the current
year due to the termination of low-margin purchase contracts subsequent to the
discovery of the unauthorized trading losses.
In the period immediately following the disclosure of the unauthorized trading
losses, a significant number of our suppliers and trading partners reduced or
eliminated the open credit previously extended to us. Consequently, the amount
of letters of credit we needed to support the level of our crude oil purchases
then in effect increased significantly. In addition, the cost of obtaining
letters of credit increased under our amended credit facility. In many instances
we arranged for letters of credit to secure our obligations to purchase crude
oil from our customers, which increased our letter of credit costs and decreased
our unit margins. In other instances, primarily involving lower-margin wellhead
and bulk purchases, our purchase contracts were terminated.
Midstream general and administrative expenses were $16.6 million for the six
months ended June 30, 2000, compared to $8.2 million for the first half of 1999.
The increase in 2000 is primarily due to the Scurlock acquisition in May 1999
(approximately $5.7 million) and consulting fees related to the trading loss
investigation and assistance in review and implementation of enhanced controls
(approximately $1.8 million).
Midstream depreciation and amortization expense was $14.9 million for the six
months ended June 30, 2000, compared to $6.7 million for the first half of 1999.
The increase is primarily due to the Scurlock and West Texas gathering system
acquisitions in mid-1999 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.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
------------------------------
(in millions) 2000 1999
--------------------------------------------------------------------
(RESTATED)
<S> <C> <C>
Cash provided by (used in):
Operating activities $ 3.7 $ 25.8
Investing activities 188.5 (199.0)
Financing activities (248.3) 179.6
--------------------------------------------------------------------
</TABLE>
Operating Activities. Net cash provided by operating activities for the first
half of 2000 decreased from the 1999 amounts 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.
Investing Activities. Net cash provided by investing activities for the first
half of 2000 included $224.0 million of proceeds from the sales of the segment
of the All American Pipeline and pipeline linefill.
Financing activities. Net cash used in financing activities for the first half
of 2000 resulted primarily from net payments of $221.0 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 cash dividends of approximately $6.0 million on our
Series D, F and G preferred stock. The dividends on the Series D and F preferred
stock are for the period from October 1, 1999 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.
28
<PAGE>
Credit Facilities
Amounts outstanding under our credit agreements at June 30, 2000 were as
follows (in thousands):
<TABLE>
<S> <C>
Revolving credit facility $ 15,000
Plains Marketing, L.P. revolving credit facility 267,250
Plains Marketing, L.P. letter of credit and hedged inventory facility 3,000
--------
$285,250
========
</TABLE>
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 June 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 June
30, 2000, letters of credit of $0.6 million were outstanding under 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 currently in
compliance with the covenants contained in the revolving credit facility. At
June 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 up to $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.
. 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 June 30, 2000,
approximately $129.4 million in letters of credit were outstanding under the
letter of credit and borrowing facility.
29
<PAGE>
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 PPA'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 contained in its bank credit agreements. At
June 30, 2000, PAA could have borrowed the full $400.0 million available 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 in the
Delaware Chancery Court 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 $28.73 per barrel during the first half of 2000, approximately 87%
above the $15.35 per barrel in the first half 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 second half 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 $19.75 per barrel. This hedge position is equivalent to
approximately 81% of the first half of 2000 average daily crude oil volumes,
which at average second quarter prices we will 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 $21.88 per barrel on 18,000 barrels per day (equivalent to 78% of
first half 2000 crude oil production levels) with full market price
participation up to an average of $26.00 per barrel. For market prices between
$26.00 and $29.00 per barrel, we will receive an average of approximately 95% of
market price and at market prices over $29.00 per barrel, we will receive
approximately 90% of market price. For 2002, we have entered into various
arrangements which provide for us to receive an average minimum NYMEX WTI price
of $24.40 per barrel on 1,750 barrels per day. The foregoing NYMEX WTI crude oil
prices are before quality and location differentials and the cost of the hedges,
which averaged approximately $0.80 per barrel. Approximately 80% of these hedges
were entered into prior to June 30, 2000. 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.
30
<PAGE>
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 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. This statement was amended by SFAS No. 137, Accounting for
Derivative Instruments and Hedging Activities - Deferral of the Effective Date
of FASB Statement No. 133 ("SFAS 137") issued in June 1999. SFAS 137 deferred
the effective date of SFAS 133 to fiscal years beginning after June 15, 2000. We
are required to adopt this statement beginning January 1, 2001. We have not yet
determined what impact the adoption of SFAS 133 would have on the consolidated
balance sheets, statements of operations and cash flows; however, this standard
could increase volatility in earnings and retained earnings (deficit) through
comprehensive income. In June 2000, the FASB issued SFAS 138, "Accounting for
Certain Derivative Instruments and Certain Hedge Activities." SFAS 138 amended
the portions of SFAS 133, inclusive of the definition of the normal purchase and
sale exclusion.
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 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>
JUNE 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 $ 8.2 $ 5.5 $ - $(2.8)
Swaps and options contracts (40.7) (11.8) (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.
31
<PAGE>
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 June 30, 2000, the carrying value of all variable rate
bank debt of $285.3 million approximated the fair value at that date. The
carrying value and fair value of the fixed rate debt was $277.5 million and
$274.8 million, respectively, at that date. The carrying value and fair value of
redeemable preferred stock were $138.8 million and $168.4 million, respectively,
at June 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 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 June 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 $1.2 million as of such date. These instruments are based on LIBOR
margins 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.
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.
32
<PAGE>
PART II. OTHER INFORMATION
ITEMS 2, 3 & 5 ARE NOT APPLICABLE AND HAVE BEEN OMITTED
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, et al. The suit alleged
that Plains All American Pipeline, L.P. and certain of the general partner's
officers and directors violated federal securities laws, primarily in connection
with unauthorized trading by a former employee. An additional nineteen cases
were filed in the Southern District of Texas, some of which name the general
partner and us as additional defendants. The court consolidated all subsequently
filed cases under the first filed action described above and appointed two lead
plaintiffs representing two different plaintiff classes: (1) purchasers of our
common stock and options (the "Plains Plaintiffs") and (2) purchasers of PAA's
common units (the "PAA Plaintiffs"). On July 14, 2000, the Plains Plaintiffs
filed a consolidated complaint alleging violations of Rule 10b-5 and Section
20(a) of the Securities Exchange Act of 1934. On the same day, the PAA
Plaintiffs filed a consolidated complaint, naming as additional defendants the
underwriters for the public offering of PAA units. The PAA Plaintiffs'
consolidated complaint alleges that the defendants are 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.
The plaintiffs in the Texas securities litigation seek, among other things,
damages for all losses and damages allegedly sustained by the plaintiffs from
the unauthorized trading loss and defendants' alleged misconduct, and any
additional relief as may be just and proper under the circumstances.
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 responsive pleading or motion on behalf of the defendants is
due 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 Plains All American Pipeline, L.P. and its unitholders by failing
to monitor properly the activities of its employees. The derivative complaints
allege, among other things, that Plains All American Pipeline has been harmed
due to the negligence or breach of fiduciary duties of the officers and
directors that are named in the lawsuits. 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. No responsive pleading or
motion on behalf of the defendants is currently due.
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
securities litigation, 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 or results of operations.
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.
33
<PAGE>
Item 4. - Submission of Matters to a Vote of Security Holders
The 2000 Annual Meeting of Stockholders (the "Meeting") of the Company was
held on June 7, 2000. At the Meeting, holders of common stock, $.10 par
value, of the Company ("Common Stock"), elected eight members of the
Company's Board of Directors. No other matters were voted on at the Meeting.
Out of the 17,979,237 shares of Common Stock entitled to vote at the Meeting,
there were 13,865,377 shares of Common Stock represented at the Meeting
either by proxies solicited in accordance with Schedule 14A or by security
holders voting in person.
The tabulation of votes for each director nominee is as follows:
NOMINEES FOR ELECTION TO THE
COMPANY'S BOARD OF DIRECTORS VOTES "FOR" WITHHELD
---------------------------------- ----------------- --------------
Greg Armstrong 13,249,155 616,222
Jerry L. Dees 13,828,995 36,382
Tom H. Delimitros 13,828,995 36,382
William H. Hitchcock 13,828,694 36,683
Dan M. Krausse 13,828,988 36,389
John H. Lollar 13,828,995 36,382
Robert V. Sinnott 13,828,990 36,457
J. Taft Symonds 13,828,995 36,382
Item 6 - Exhibits and Reports on Form 8-K
A. Exhibits
10.1 Sixth Amendment to the Fourth Amended and Restated Credit Agreement dated
June 12, 2000, among the Company and First Union National Bank, et al.
27.1 Financial Data Schedule
B. Reports on Form 8-K
A Current Report on Form 8-K was filed on June 15, 2000, with respect to
the stock repurchase program approved by our Board of Directors.
34
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned and thereunto duly authorized.
PLAINS RESOURCES INC.
Date: August 14, 2000 By: /s/ Cynthia A. Feeback
----------------------------------
Cynthia A. Feeback, Vice President -
Accounting and Assistant Treasurer
(Principal Accounting Officer)
35
