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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, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission file number: 1-14569
PLAINS ALL AMERICAN PIPELINE, L.P.
(Exact name of registrant as specified in its charter)
Delaware 76-0582150
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
333 Clay Street
Houston, Texas 77002
(Address of principal executive offices)
(Zip Code)
(713) 646-4100
(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
--- ---
At August 8, 2001, there were outstanding 27,015,939 Common Units, 1,307,190
Class B Common Units and 10,029,619 Subordinated Units.
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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
TABLE OF CONTENTS
Page
----
PART I. FINANCIAL INFORMATION
CONSOLIDATED FINANCIAL STATEMENTS:
Consolidated Balance Sheets:
June 30, 2001 and December 31, 2000........................... 3
Consolidated Statements of Income:
For the three and six months ended June 30, 2001 and 2000..... 4
Consolidated Statements of Cash Flows:
For the six months ended June 30, 2001 and 2000............... 5
Consolidated Statement of Partners' Capital:
For the six months ended June 30, 2001........................ 6
Notes to Consolidated Financial Statements......................... 7
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS........................... 15
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISKS.................................................. 23
PART II. OTHER INFORMATION......................................... 24
2
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
JUNE 30, DECEMBER 31,
2001 2000
----------- ------------
(UNAUDITED)
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 1,054 $ 3,426
Accounts receivable and other current assets 439,547 347,698
Inventory 125,852 46,780
---------- --------
Total current assets 566,453 397,904
---------- --------
PROPERTY AND EQUIPMENT 624,893 467,619
Less allowance for depreciation and amortization (36,651) (26,974)
---------- --------
588,242 440,645
---------- --------
OTHER ASSETS
Pipeline linefill 41,525 34,312
Other 17,612 12,940
---------- --------
$1,213,832 $885,801
========== ========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable and other current liabilities $ 423,305 $328,542
Due to affiliates 17,997 20,951
Short-term debt and current portion of long-term debt 96,527 1,300
---------- --------
Total current liabilities 537,829 350,793
---------- --------
LONG-TERM LIABILITIES
Bank debt 372,580 320,000
Other long-term liabilities and deferred credits 1,017 1,009
---------- --------
Total liabilities 911,426 671,802
---------- --------
COMMITMENTS AND CONTINGENCIES (NOTE 11)
PARTNERS' CAPITAL
Common unitholders (27,015,939 and 23,049,239 units outstanding
at June 30, 2001 and December 31, 2000 respectively) 303,323 217,073
Class B common unitholders (1,307,190 units outstanding) 20,341 21,042
Subordinated unitholders (10,029,619 units outstanding) (32,699) (27,316)
General partner 11,441 3,200
---------- --------
Total partners' capital 302,406 213,999
---------- --------
$1,213,832 $885,801
========== ========
See notes to consolidated financial statements.
3
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(in thousands, except per unit data)
(unaudited)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30 JUNE 30,
------------------ ------------------
2001 2000 2001 2000
---- ---- ---- -----
REVENUES $1,586,617 $1,481,834 $3,106,741 $3,484,341
COST OF SALES AND OPERATIONS 1,550,230 1,449,060 3,037,624 3,415,015
---------- ---------- ---------- ----------
Gross Margin 36,387 32,774 69,117 69,326
---------- ---------- ---------- ----------
EXPENSES
General and administrative 15,041 7,949 24,030 16,575
Depreciation and amortization 6,503 4,661 11,173 14,799
---------- ---------- ---------- ----------
Total expenses 21,544 12,610 35,203 31,374
---------- ---------- ---------- ----------
OPERATING INCOME 14,843 20,164 33,914 37,952
Interest expense (8,101) (6,150) (14,707) (15,308)
Gain on sale of assets - - - 48,188
Interest and other income 325 3,049 367 10,531
---------- ---------- ---------- ----------
Income before extraordinary item and cumulative
effect of accounting change 7,067 17,063 19,574 81,363
Extraordinary item - (11,002) - (15,147)
Cumulative effect of accounting change (Note 5) - - 508 -
---------- ---------- ---------- ----------
NET INCOME $ 7,067 $ 6,061 $ 20,082 $ 66,216
========== ========== ========== ==========
NET INCOME - LIMITED PARTNERS $ 6,794 $ 5,874 $ 19,483 $ 64,826
========== ========== ========== ==========
NET INCOME - GENERAL PARTNER $ 273 $ 187 $ 599 $ 1,390
========== ========== ========== ==========
BASIC AND DILUTED NET INCOME
PER LIMITED PARTNER UNIT
Income before extraordinary item and
cumulative effect of accounting change $ 0.19 $ 0.49 $ 0.54 $ 2.32
Extraordinary item - (0.32) - (0.43)
Cumulative effect of accounting change - - 0.02 -
---------- ---------- ---------- ----------
Net income $ 0.19 $ 0.17 $ 0.56 $ 1.89
========== ========== ========== ==========
WEIGHTED AVERAGE UNITS
OUTSTANDING 35,685 34,386 35,039 34,386
========== ========== ========== ==========
See notes to consolidated financial statements.
4
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)
SIX MONTHS ENDED
JUNE 30,
-------------------
2001 2000
---- ----
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 20,082 $ 66,216
Items not affecting cash flows
from operating activities:
Depreciation and amortization 11,173 14,799
Gain on the sale of assets - (48,188)
Cumulative effect of accounting change (508) -
Change in derivative fair value 652 -
Other noncash items 5,741 4,712
Change in assets and liabilities, net of assets acquired and
liabilities assumed:
Accounts receivable and other current assets (85,477) 162,125
Inventory (77,119) 2,493
Accounts payable and other current liabilities 81,424 (207,607)
Due to affiliates (2,947) -
Pipeline linefill - (929)
Other long-term liabilities and deferred credits - (29)
----------- ---------
Net cash used in operating activities (46,979) (6,408)
----------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions (160,584) -
Additions to property and equipment and other assets (9,412) (5,548)
Proceeds from sales of assets 1,077 223,859
----------- ---------
Net cash provided by (used in) investing activities (168,919) 218,311
----------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Advances (to) from affiliates - (18,029)
Proceeds from long-term debt 1,114,780 443,050
Proceeds from short-term debt 193,150 45,250
Payment of subordinated debt - general partner - (114,000)
Principal payments of long-term debt (1,061,200) (485,900)
Principal payments of short-term debt (98,345) (100,969)
Costs incurred in connection with financing arrangements (7,972) (6,500)
Proceeds from issuance of units 106,209 -
Distributions to unitholders (33,096) (26,973)
----------- ---------
Net cash provided by (used in) financing activities 213,526 (264,071)
----------- ---------
Net increase (decrease) in cash and cash equivalents (2,372) (52,168)
Cash and cash equivalents, beginning of period 3,426 53,768
----------- ---------
Cash and cash equivalents, end of period $ 1,054 $ 1,600
=========== =========
See notes to consolidated financial statements.
5
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
(in thousands)
(unaudited)
TOTAL
CLASS B GENERAL PARTNERS'
COMMON UNITS COMMON UNITS SUBORDINATED UNITS PARTNER CAPITAL
--------------- ---------------- ------------------ ------- --------
UNITS AMOUNT UNITS AMOUNT UNITS AMOUNT AMOUNT AMOUNT
----- ------ ----- ------ ----- ------ ------ -------
Balance at December 31, 2000 23,049 $217,073 1,307 $21,042 10,030 $(27,316) $ 3,200 $213,999
Issuance of units 3,967 98,640 - - - - 2,878 101,518
Noncash compensation expense - - - - - - 5,741 5,741
Distributions - (21,608) - (1,225) - (9,403) (860) (33,096)
Other comprehensive income - (3,941) - (205) - (1,575) (117) (5,838)
Net income - 13,159 - 729 - 5,595 599 20,082
------ -------- ----- ------- ------ -------- ------- --------
Balance at June 30, 2001 27,016 $303,323 1,307 $20,341 10,030 $(32,699) $11,441 $302,406
====== ======== ===== ======= ====== ======== ======= ========
See notes to consolidated financial statements.
6
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Note 1 -- Organization and Accounting Policies
We are a Delaware limited partnership that was formed in September, 1998
to acquire and operate the midstream crude oil business and assets of Plains
Resources Inc. and its wholly owned subsidiaries. On November 23, 1998, we
completed our initial public offering and the transactions whereby we became the
successor to the business of the midstream subsidiaries of Plains Resources. Our
operations are conducted through Plains Marketing, L.P., All American Pipeline,
L.P. and Plains Marketing Canada, L.P. The terms "Plains All American" and the
"Partnership" herein refer to Plains All American Pipeline, L.P. and its
affiliated operating partnerships. We are engaged in interstate and intrastate
transportation, marketing, and terminalling of crude oil. Our operations are
conducted primarily in Texas, California, Oklahoma, Louisiana, the Gulf of
Mexico and the Canadian Provinces of Alberta and Saskatchewan.
The accompanying financial statements and related notes present our
consolidated financial position as of June 30, 2001 and December 31, 2000; the
results of our operations for the three and six months ended June 30, 2001 and
2000; cash flows for the six months ended June 30, 2001 and 2000; and changes in
partners' capital for the six months ended June 30, 2001. The financial
statements have been prepared in accordance with the instructions to interim
reporting as prescribed by the Securities and Exchange Commission ("SEC"). All
adjustments consisting only of normal recurring adjustments that, in the opinion
of management, were necessary for a fair statement of the results for the
interim periods, have been reflected. All significant intercompany transactions
have been eliminated. Certain reclassifications have been made to prior period
amounts to conform with current period presentation. The results of operations
for the three and six months ended June 30, 2001 should not be taken as
indicative of the results to be expected for the full year. The interim
financial statements should be read in conjunction with our consolidated
financial statements and notes thereto presented in our 2000 Annual Report on
Form 10-K.
Note 2 -- Transfer of Our General Partner
On June 8, 2001, Plains All American Inc., our former general partner and a
wholly owned subsidiary of Plains Resources Inc., sold a portion of its
ownership in our partnership to an investor group including, among others,
affiliates of Kayne Anderson Capital Advisors, EnCap Investments, Strome
Investment Management, James C. Flores and our current management for aggregate
consideration of approximately $155.2 million.
In connection with this transaction, a new entity jointly owned by the
investor group and Plains Resources Inc. became our general partner and assumed
all of the general partner's rights and obligations under our partnership
agreement. The investor group purchased approximately 5.2 million subordinated
units from an affiliate of Plains Resources Inc. As a result of this
transaction and our recent equity offering, Plains Resources' effective
ownership in us has been reduced to approximately 33% from approximately 54%.
Plains Resources has agreed to make available to our management group an
additional 2% of the general partner interest on substantially the same terms as
the other investors.
Note 3 -- Equity Offering
On May 31, 2001, we completed a public offering of 3,750,000 common units.
Additionally, on June 22, 2001, we issued another 216,700 units pursuant to the
underwriter's overallotment option. Total net cash proceeds from the offering
(which aggregates to 3,966,700 units), including our general partner's
proportionate contribution, were approximately $100.7 million and were used to
repay borrowings under our revolving credit facility, a portion of which were
used to finance the Murphy Acquisition (see Note 6).
Note 4 -- Derivative Instruments and Hedging Activities
On January 1, 2001, we adopted Statement of Financial Accounting Standards
("SFAS") No. 133 "Accounting for Derivative Instruments and Hedging Activities"
as amended by SFAS 137 and SFAS 138. Under SFAS 133, all derivative instruments
are recorded on the balance sheet at fair value. If the derivative does not
qualify as a hedge or is not designated as a hedge, the gain or loss on the
derivative is recognized currently in earnings. To qualify for hedge accounting,
the derivative must qualify either as a fair value hedge, cash flow hedge or
foreign currency hedge. As of June 30, 2001, our transactions consisted of only
cash flow and foreign currency hedges (which are defined as fair value hedges)
and the remaining discussion will relate exclusively to these types of
derivative instruments. If the derivative qualifies for cash flow hedge
accounting, the gain or loss on the derivative is deferred in accumulated Other
Comprehensive Income ("OCI"), a
7
component of Partners' Capital, to the extent the hedge is effective. Fair
value hedge gains or losses are taken directly to earnings in the current
period.
The relationship between the hedging instrument and the hedged item must be
highly effective in achieving the offset of changes in cash flows attributable
to the hedged risk both at the inception of the contract and on an ongoing
basis. Hedge accounting is discontinued prospectively when a hedge instrument
becomes ineffective. Gains and losses deferred in OCI related to cash flow
hedges that become ineffective remain unchanged until the related product is
delivered. If it is determined that it is probable that a hedged forecasted
transaction will not occur, deferred gains or losses on the hedging instrument
are recognized in earnings immediately.
Gains and losses on hedging instruments related to OCI and adjustments to
carrying amounts on hedged volumes are included in revenues in the period that
the related volumes are delivered. Gains and losses of hedging instruments,
which represent hedge ineffectiveness, are included in earnings in the period in
which they occur.
We utilize various derivative instruments, for purposes other than trading,
to hedge our exposure to price fluctuations on crude in storage and expected
purchases, sales and transportation of crude oil. The derivative instruments
consist primarily of futures and option contracts traded on the New York
Mercantile Exchange. We also utilize interest rate collars to manage the
interest rate exposure on our long-term debt and foreign currency hedges to
manage exchange rate exposure.
On January 1, 2001, in accordance with the transition provisions of SFAS
133, we recorded a loss of $8.3 million in OCI representing the cumulative
effect of an accounting change to recognize at fair value all cash flow
derivatives. We also recorded a noncash gain of $0.5 million in earnings as a
cumulative effect adjustment.
At June 30, 2001, a $5.8 million unrealized loss was recorded to OCI
together with related assets and liabilities of $6.9 million and $12.9 million,
respectively. Earnings included a non-cash gain of $0.2 million related to the
ineffective portion of our cash flow hedges, as well as the gain/loss on our
fair value hedges (included in revenues in the income statement). Our
hedge-related assets and liabilities are included in other current assets and
other current liabilities in the balance sheet.
As of June 30, 2001, the total amount of deferred net losses on derivative
instruments recorded in OCI are expected to be reclassified to earnings during
the next twelve-month period. At June 30, 2001 we had the following open crude
oil hedge positions:
2001 2002
------------------ -------------------
3rd Qtr 4th Qtr 1st Qtr 2nd Qtr
------- ------- ------- -------
Volume (bbls)
Short positions 812,000 - - -
Long positions - 762,000 132,000 250,000
Average price ($/bbl) $25.13 $26.84 $27.28 $25.56
At June 30, 2001, we had an interest rate collar arrangement to protect interest
rate fluctuations on a portion of our outstanding debt for an aggregate notional
principal amount of $125.0 million. This instrument is based on LIBOR rates and
provides for a floor of 6.1% and a ceiling of 8.0% with an expiration date of
August 2002.
During the second quarter of 2001, gains of $.5 million were relieved from
OCI and the fair value of open positions decreased $2.7 million. Additionally,
certain derivative positions were terminated prior to maturity. As such, a $5.8
million loss related to all positions (open and closed hedges) was recorded in
OCI at June 30, 2001.
We formally document all relationships between hedging instruments and
hedged items, as well as our risk management objectives and strategy for
undertaking the hedge. Hedge effectiveness is measured on a quarterly basis.
This process includes specific identification of the hedging instrument and the
hedge transaction, the nature of the risk being hedged and how the hedging
instrument's effectiveness will be assessed. Both at the inception of the hedge
and on an ongoing basis, we assess whether the derivatives that are used in
hedging transactions are highly effective in offsetting changes in cash flows of
hedged items. No amounts were excluded from the computation of hedge
effectiveness.
Note 5 -- Comprehensive Income
Comprehensive income includes net income and certain items recorded
directly to Partners' Capital and classified as OCI. Following the adoption of
SFAS 133, we recorded a charge to OCI of $8.3 million related to the change in
fair value
8
of certain derivative financial instruments that qualified for cash flow hedge
accounting. The following table reflects comprehensive income for the six months
ended June 30, 2001 (in thousands of dollars):
Total Comprehensive Income at January 1, 2001 $ -
Cumulative effect of change in accounting principle (8,337)
Reclassification adjustment for settled contracts 6,791
Changes in fair value of open hedging positions (4,340)
Currency translation adjustment 48
-------
Other Comprehensive Income at June 30, 2001 (5,838)
Net income for the six months ended June 30, 2001 20,082
-------
Total Comprehensive Income at June 30, 2001 $14,244
=======
Note 6 -- Acquisitions
Murphy Oil Company Ltd. Midstream Operations
In May 2001, we closed the acquisition of substantially all of the crude
oil pipeline, gathering, storage and terminalling assets of Murphy Oil Company
Ltd. for approximately $161 million in cash ("the Murphy Acquisition"),
including financing and transaction costs. The purchase included $7.2 million
for excess inventory in the pipeline systems. The principal assets acquired
include approximately 450 miles of crude oil and condensate transmission
mainlines and associated gathering and lateral lines, approximately 1.1 million
barrels of crude oil storage and terminalling capacity located primarily in
Kerrobert, Saskatchewan, approximately 200,000 barrels of pipeline linefill, an
inactive 108-mile mainline system and 121 trailers used primarily for crude oil
transportation. We have reactivated the 108-mile mainline system and began
shipping volumes in May of 2001.
Murphy has agreed to continue to transport production from fields
previously delivering crude oil to these pipeline systems, under a new long-term
contract. The current volume is approximately 11,000 barrels per day. The
pipeline systems transport approximately 200,000 barrels per day of light,
medium and heavy crudes, as well as condensate.
The Murphy Acquisition has been accounted for using the purchase method of
accounting and the purchase price was allocated in accordance with Accounting
Principles Board Opinion No. 16, Business Combinations, ("APB 16") as follows
(in thousands):
Crude oil pipeline, gathering and terminal assets $150,182
Pipeline linefill 7,602
Net working capital items 1,953
Other property and equipment 487
Other assets, including debt issue costs 360
--------
Total $160,584
========
Pro Forma Results for the Murphy Acquisition
The following unaudited pro forma data is presented to show pro forma
revenues, net income and basic and diluted net income per limited partner unit
for the partnership as if the Murphy Acquisition and the equity offering
discussed in Note 3 had occurred on January 1, 2000 (in thousands):
9
SIX MONTHS
ENDED JUNE 30,
----------------
2001 2000
---- ----
Revenues $3,268,006 $3,819,106
========== ==========
Income before extraordinary item
and cumulative effect of accounting
change $ 23,629 $ 83,468
========== ==========
Net income $ 24,137 $ 68,321
========== ==========
Basic and diluted income before
extraordinary item and cumulative
effect of accounting change per
limited partner unit $ 0.65 $ 2.38
========== ==========
Basic and diluted net income
per limited partner unit $ 0.67 $ 1.94
========== ==========
CANPET Energy Group Inc.
In July 2001, we acquired the assets of CANPET Energy Group Inc.
("CANPET"), a Calgary-based Canadian crude oil and liquefied petroleum gas
marketing company, for approximately $42.0 million plus excess inventory at the
closing date of approximately $25 million. Approximately $24.0 million of the
purchase price, plus the excess inventory, was paid in cash at closing and the
remainder, which is subject to certain performance standards, will be paid in
common units in April 2004 if such standards are met. CANPET activities include
gathering approximately 75,000 barrels per day of crude oil and marketing
approximately 26,000 barrels per day of natural gas liquids. Tangible assets
include a crude oil handling facility, a 130,000-barrel tank facility and
working capital of approximately $8.6 million. Financing for the acquisition was
provided through borrowings under our bank credit facility.
Note 7 -- Credit Agreements
In May 2001, we entered into new amended and restated credit facilities
that replaced our existing credit facilities. Our credit facilities currently
consist of:
. a $630.0 million senior secured revolving credit and term loan facility,
which is secured by substantially all of our assets. The facility consists of
a $500.0 million domestic revolving facility (with a $10.0 million letter of
credit sublimit), a $30.0 million Canadian revolving facility (with a $5.0
million letter of credit sublimit) and a $100.0 million term loan. The
facility matures, as to the aggregate $530.0 million domestic and Canadian
revolver portions, in April, 2005 and, as to the $100.0 million term portion,
in May, 2006. On the revolver portions, no principal is scheduled for payment
prior to maturity; however, if we issue privately-placed or public debt, the
net proceeds of such debt must be used to repay then-outstanding loans under
the domestic revolver, and with the repayment and depending on the amount of
net proceeds, the domestic revolver commitment will be reduced by 40% to 50%
of its original amount. The term portion of this facility has four scheduled
annual payments of principal, commencing May 4, 2002, in the respective
amounts of 1%, 7%, 8% and 8% of the original term principal amount, with the
remaining principal balance scheduled for payment on the stated maturity date
of May 5, 2006. If any part of the term portion is prepaid prior to its first
anniversary, a 1% premium will be due on that portion. The revolving credit
and term loan facility bears interest at our option at either the base rate,
as defined, plus an applicable margin, or LIBOR plus an applicable margin,
and further, the Canadian revolver may effectively bear interest based upon
bankers' acceptance rates. We incur a commitment fee on the unused portion of
the revolver portion of this credit facility.
. A $200.0 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 and other specified petroleum products for
resale and borrowings to finance crude oil inventory and other specified
petroleum products that have been hedged against future price risk. The
letter of credit facility is secured by substantially all of our assets and
has a sublimit for cash borrowings of $100.0 million to purchase crude oil
and other petroleum products that have been hedged against future price risk
and to fund margin requirements under NYMEX contracts used to facilitate our
hedging activities. The letter of credit facility expires in April, 2004.
Aggregate availability under the letter of credit facility for direct
borrowings and letters of credit is limited to a borrowing base that is
determined monthly based on certain of our current assets and current
liabilities, primarily inventory and accounts receivable and accounts payable
related to the purchase and sale of crude oil and other specified petroleum
products.
10
Our credit facilities 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 our 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.
Our credit facilities treat a change of control as an event of default and
also require us to maintain:
. a current ratio (as defined) of 1.0 to 1.0;
. a debt coverage ratio which is not greater than 4.75 to 1.0 through September
29, 2001, 4.50 to 1 from September 30, 2001 through June 29, 2002, 4.25 to 1.0
from June 30, 2002 through December 30, 2002 and 4.0 to 1.0 thereafter;
. an interest coverage ratio which is not less than 2.75 to 1.0; and
. a debt to capital ratio of not greater than 0.73 to 1.0 prior to December 31,
2002 and 0.65 to 1.0 thereafter.
A default under our credit facilities 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 we are in compliance with our
commercial credit agreements, they do not restrict our ability to make
distributions of "available cash" as defined in our partnership agreement. We
are currently in compliance with the covenants contained in our credit
agreements.
Note 8 -- Distributions
On February 14, 2001 we paid a cash distribution of $0.4625 per unit on our
outstanding common units, Class B units and subordinated units. The distribution
was paid to unitholders of record on February 7, 2001 for the period October 1,
2000 through December 31, 2000. The total distribution paid was approximately
$16.3 million, with approximately $7.5 million paid to our public unitholders
and the remainder paid to our prior general partner for its limited and general
partner interests. The distribution was in excess of the minimum quarterly
distribution specified in the Partnership Agreement.
On May 15, 2001, we paid a cash distribution of $0.475 per unit on our
outstanding common units, Class B units and subordinated units. The distribution
was paid to unitholders of record on May 3, 2001 for the period January 1, 2001
through March 31, 2001. The total distribution paid was approximately $16.8
million, with approximately $7.7 million paid to our public unitholders and the
remainder to our prior general partner for its limited and general partner
interests.
On July 24, 2001 we declared a cash distribution of $0.50 per unit on our
outstanding common units, Class B units and subordinated units. The distribution
is payable on August 14, 2001 to holders of record on August 3, 2001. The total
distribution to be paid is approximately $19.9 million, with approximately $13.5
million to be paid to our common unitholders, $0.7 million to our Class B common
unitholders, $5.0 million to our subordinated unitholders, and the remainder to
be paid to our general partner for its general partner interests.
Note 9 -- Operating Segments
Our operations consist of two operating segments: (1) Pipeline Operations -
engages in interstate and intrastate crude oil pipeline transportation and
related merchant activities; and (2) Gathering, Marketing, Terminalling and
Storage Operations - engages in purchases and resales of crude oil at various
points along the distribution chain and the leasing of terminalling and storage
facilities.
11
MARKETING,
GATHERING,
TERMINALLING
(IN THOUSANDS) (UNAUDITED) PIPELINE & STORAGE TOTAL
- -------------------------------------------------------------------------------------------------------------
THREE MONTHS ENDED JUNE 30, 2001
Revenues:
External Customers $ 91,815 $ 1,494,802 $ 1,586,617
Intersegment (a) 5,166 1,245 6,411
Other revenue - 325 325
--------- ----------- -----------
Total revenues of reportable segments $ 96,981 $ 1,496,372 $ 1,593,353
========= =========== ===========
Segment gross margin (b) $ 18,699 $ 17,688 $ 36,387
Segment gross profit (c) 17,668 9,298 26,966
Income allocated to reportable segments (d) 10,929 1,758 12,687
Noncash compensation expense n/a n/a 5,620
--------- ----------- -----------
Income before extraordinary item and cumulative effect
of accounting change n/a n/a $ 7,067
========= =========== ===========
Total assets 451,887 761,945 1,213,832
- -------------------------------------------------------------------------------------------------------------
THREE MONTHS ENDED JUNE 30, 2000
Revenues:
External Customers $ 106,520 $ 1,375,314 $ 1,481,834
Intersegment (a) 6,083 - 6,083
Other 2,706 343 3,049
--------- ----------- -----------
Total revenues of reportable segments $ 115,309 $ 1,375,657 $ 1,490,966
========= =========== ===========
Gain on sale of assets
Segment gross margin (b) $ 12,759 $ 20,015 $ 32,774
Segment gross profit (c) 12,093 12,732 24,825
Income allocated to reportable segments 10,718 6,345 17,063
Noncash compensation expense n/a n/a -
--------- ----------- -----------
Income before extraordinary item and cumulative
effect of accounting change n/a n/a $ 17,063
========= =========== ===========
Total assets 319,558 499,750 819,308
- -------------------------------------------------------------------------------------------------------------
SIX MONTHS ENDED JUNE 30, 2001
Revenues:
External Customers $ 179,853 $ 2,926,888 $ 3,106,741
Intersegment (a) 8,475 1,245 9,720
Other revenue - 367 367
--------- ----------- -----------
Total revenues of reportable segments $ 188,328 $ 2,928,500 $ 3,116,828
========= =========== ===========
Segment gross margin (b) $ 32,591 $ 36,526 $ 69,117
Segment gross profit (c) 31,100 19,728 50,828
Income allocated to reportable segments (d) 20,979 4,336 25,315
Noncash compensation expense n/a n/a 5,741
--------- ----------- -----------
Income before extraordinary item and cumulative effect
of accounting change n/a n/a $ 19,574
========= =========== ===========
Total assets 451,887 761,945 1,213,832
- -------------------------------------------------------------------------------------------------------------
SIX MONTHS ENDED JUNE 30, 2000
Revenues:
External Customers $ 286,578 $ 3,197,763 $ 3,484,341
Intersegment (a) 60,498 - 60,498
Other 9,679 852 10,531
--------- ----------- -----------
Total revenues of reportable segments $ 356,755 $ 3,198,615 $ 3,555,370
========= =========== ===========
Gain on sale of assets $ 48,188 $ - $ 48,188
Segment gross margin (b) 25,914 43,412 69,326
Segment gross profit (c) 24,291 28,591 52,882
Income allocated to reportable segments (d) 73,105 8,389 81,494
Noncash compensation expense n/a n/a 131
--------- ----------- -----------
Income before extraordinary item and cumulative effect
of accounting change n/a n/a $ 81,363
========= =========== ===========
Total assets 319,558 499,750 819,308
- -------------------------------------------------------------------------------------------------------------
12
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
expenses and general and administrative expenses, excluding noncash
compensation expense.
d) Excludes noncash compensation expense, as it is not allocated to the
reportable segments.
Note 10 -- Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statements of Financial Accounting Standards No. 141 "Business Combinations"
("SFAS 141") and No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142").
SFAS 141 requires all business combinations initiated after June 30, 2001, to be
accounted for under the purchase method. For all business combinations for
which the date of acquisition is after June 30, 2001, this Standard also
establishes specific criteria for the recognition of intangible assets
separately from goodwill and requires unallocated negative goodwill to be
written off immediately as an extraordinary gain, rather than deferred and
amortized. SFAS 142 changes the accounting for goodwill and other intangible
assets after an acquisition. The most significant changes made by SFAS 142 are:
1) goodwill and intangible assets with indefinite lives will no longer be
amortized; 2) goodwill and intangible assets with indefinite lives must be
tested for impairment at least annually; and 3) the amortization period for
intangible assets with finite lives will no longer be limited to forty years.
At this time, we cannot reasonably estimate the effect of the adoption of this
statement on either our financial position, results of operations, or cash
flows.
We will account for all future business combinations, including the CANPET
acquisition, under SFAS 141. Effective January 1, 2002, we will adopt SFAS 142,
as required. At that time, amortization will cease on the unamortized portion
of the goodwill arising from the Scurlock acquisition.
In June 2001, the FASB also approved for issuance SFAS 143 "Asset
Retirement Obligations". SFAS 143 establishes accounting requirements for
retirement obligations associated with tangible long-lived assets, including (1)
the timing of the liability recognition, (2) initial measurement of the
liability, (3) allocation of asset retirement cost to expense, (4) subsequent
measurement of the liability and (5) financial statement disclosures. SFAS 143
requires that an asset retirement cost should be capitalized as part of the cost
of the related long-lived asset and subsequently allocated to expense using a
systematic and rational method. We will adopt the statement effective January
1, 2003, as required. The transition adjustment resulting from the adoption of
SFAS 143 will be reported as a cumulative effect of a change in accounting
principle. At this time, we cannot reasonably estimate the effect of the
adoption of this statement on either our financial position, results of
operations, or cash flows.
Note 11 -- Contingencies
During 1997, the All American Pipeline experienced a leak in a segment of
its pipeline in California that resulted in an estimated 12,000 barrels of crude
oil being released into the soil. Immediate action was taken to repair the
pipeline leak, contain the spill and to recover the released crude oil. We have
expended approximately $400,000 to date in connection with this spill. We do
not expect additional costs related to this site to exceed $350,000, although we
can provide no assurances in that regard.
Prior to being acquired by our predecessor in 1996, the Ingleside Terminal
experienced releases of refined petroleum products into the soil and groundwater
underlying the site due to activities on the property. We are undertaking a
voluntary state-administered remediation of the contamination on the property.
We have spent approximately $145,000 to date in investigating the contamination
at this site. We do not anticipate the total additional costs related to this
site to exceed $250,000, although no assurance can be given that the actual cost
could not exceed such estimate. In addition, a portion of any such costs may be
reimbursed to us from Plains Resources.
Litigation
Texas Securities Litigation. On November 29, 1999, a class action lawsuit
was filed in the United States District Court for the Southern District of Texas
entitled Di Giacomo v. Plains All American Pipeline, L.P., et al. The suit
alleged that Plains All American and certain of the officers and directors of
Plains All American Inc. (our general partner at the time) violated federal
securities laws, primarily in connection with unauthorized trading by a former
employee. An additional
13
nineteen cases were filed in the Southern District of Texas, some of which name
Plains All American Inc. and Plains Resources as additional defendants. All of
the federal securities claims have been consolidated into two actions. The first
consolidated action is that filed by purchasers of Plains Resources' common
stock and options, and is captioned Koplovitz v. Plains Resources Inc., et al.
The second consolidated action is that filed by purchasers of our common units,
and is captioned Di Giacomo v. Plains All American Pipeline, L.P., et al.
Plaintiffs alleged that the defendants were liable for securities fraud
violations under Rule 10b-5 and Section 20(a) of the Securities Exchange Act of
1934 and for making false registration statements under Sections 11 and 15 of
the Securities Act of 1933.
We and Plains Resources reached an agreement with representatives for the
plaintiffs for the settlement of all of the class actions, and in January 2001,
we deposited approximately $30.0 million under the terms of the settlement
agreement. The total cost of the settlement to us and Plains Resources,
including interest and expenses and after insurance reimbursements, was $14.9
million. Of that amount, $1.0 million was allocated to Plains Resources by
agreement between special independent committees of the board of directors of
Plains All American Inc. and the board of directors of Plains Resources. The
settlement is subject to final approval by the court. The settlement agreement
does not affect the Texas Derivative Litigation and Delaware Derivative
Litigation described below.
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 Plains All American Inc., 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 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 Susser v.
Plains All American Inc. as the complaint in the consolidated action. A motion
to dismiss was filed on behalf of the defendants on August 11, 2000.
The plaintiffs in the Delaware derivative litigation seek that the
defendants
. account for all losses and damages allegedly sustained by Plains All
American from the unauthorized trading losses;
. establish and maintain effective internal controls ensuring that our
affiliates and persons responsible for our affairs do not engage in
wrongful practices detrimental to Plains All American;
. pay for the plaintiffs' costs and expenses in the litigation, including
reasonable attorneys' fees, accountants' fees and experts' fees; and
. provide the plaintiffs any additional relief as may be just and proper
under the circumstances.
We have reached an agreement in principle with the plaintiffs, subject to
approval by the Delaware court, to settle the Delaware litigation for
approximately $1.1 million.
Texas Derivative Litigation. On July 11, 2000, a derivative lawsuit was
filed in the United States District Court of the Southern District of Texas
entitled Fernandes v. Plains All American Inc., et al, naming Plains All
American Inc., 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 above. A motion to dismiss was filed on behalf
of the defendants on August 14, 2000.
We intend to vigorously defend the claims made in the Texas derivative
litigation. We believe that Delaware court approval of the settlement of the
Delaware derivative litigation will effectively preclude prosecution of the
Texas derivative litigation. However, there can be no assurance that we will be
successful in our defense or that this lawsuit will not have a material adverse
effect on our financial condition, results of operation, or cash flows.
We, in the ordinary course of business, are a claimant and/or a defendant
in various other legal proceedings. Management does not believe that the outcome
of these other legal proceedings, individually and in the aggregate, will have a
materially adverse effect on our financial condition, results of operations or
cash flows.
14
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
We are a Delaware limited partnership that was formed in September of 1998
to acquire and operate the midstream crude oil business and assets of Plains
Resources Inc. and its wholly owned subsidiaries. On November 23, 1998, we
completed our initial public offering and the transactions whereby we became the
successor to the business of the midstream subsidiaries of Plains Resources. Our
operations are conducted through Plains Marketing, L.P., All American Pipeline,
L.P. and Plains Marketing Canada, L.P. We are engaged in interstate and
intrastate transportation marketing, and terminalling of crude oil. Our
operations are conducted primarily in Texas, California, Oklahoma, Louisiana,
the Gulf of Mexico and the Canadian Provinces of Alberta and Saskatchewan.
Pipeline Operations. Our activities from pipeline operations generally
consist of transporting third-party volumes of crude oil for a tariff and
merchant activities designed to capture price differentials between the cost to
purchase and transport crude oil to a sales point and the price received for
such crude oil at the sales point. Tariffs on our pipeline systems vary by
receipt point and delivery point. The gross margin generated by our 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. Our ability to generate a profit on margin activities is not tied to
the absolute level of crude oil prices but is generated by the difference
between an index-related price paid and other costs incurred in the purchase of
crude oil and an index-related price at which we sell crude oil. We are well
positioned to take advantage of these price differentials due to our ability to
move purchased volumes on our pipeline systems. We combine reporting of gross
margin for tariff activities and margin activities due to the sharing of fixed
costs between the two activities.
Terminalling and Storage Activities and Gathering and Marketing Activities.
Gross margin from terminalling and storage activities is dependent on the
throughput volume of crude oil stored and the level of fees generated at our
terminalling and storage facilities. Gross margin from our gathering and
marketing activities is dependent on our ability to sell crude oil at a price in
excess of our aggregate cost. These operations are not directly affected by the
absolute level of crude oil prices, but are affected by overall levels of supply
and demand for crude oil and fluctuations in market related indices.
Recent Events
Strategic Transaction Involving General Partner. On June 8, 2001, Plains
All American Inc., our former general partner and a wholly owned subsidiary of
Plains Resources Inc., sold a portion of its ownership in our partnership to an
investor group including, among others, affiliates of Kayne Anderson Capital
Advisors, EnCap Investments, Strome Investment Management, James C. Flores and
our current management for aggregate consideration of approximately $155.2
million.
In connection with this transaction, a new entity jointly owned by the
investor group and Plains Resources Inc. became our general partner and assumed
all of the general partner's rights and obligations under our partnership
agreement. The investor group purchased approximately 5.2 million subordinated
units from an affiliate of Plains Resources Inc. As a result of this
transaction and our recent equity offering, Plains Resources' effective
ownership in us has been reduced to approximately 33% from approximately 54%.
Plains Resources has agreed to make available for sale to our management group
an additional 2% of the general partner interest on substantially the same terms
as the other investors.
Murphy Oil Company Ltd. Midstream Operations. In May 2001, we closed the
acquisition of substantially all of the crude oil pipeline, gathering, storage
and terminalling assets of Murphy Oil Company Ltd. for approximately $161
million in cash (the "Murphy Acquisition"), including financing and transaction
costs. The purchase included $7.2 million for excess inventory in the pipeline
systems. The principal assets acquired include approximately 450 miles of crude
oil and condensate transmission mainlines and associated gathering and lateral
lines, approximately 1.1 million barrels of crude oil storage and terminalling
capacity located primarily in Kerrobert, Saskatchewan, approximately 200,000
barrels of linefill, an inactive 108-mile mainline system and 121
trailers used primarily for crude oil transportation. We have reactivated the
108-mile mainline system and began shipping volumes in May of 2001.
Murphy has agreed to continue to transport production from fields currently
delivering crude oil to these pipeline systems, under a new long-term contract.
The current volume is approximately 11,000 barrels per day. The pipeline systems
transport approximately 200,000 barrels per day of light, medium and heavy
crudes, as well as condensate.
15
CANPET Energy Group Inc. In July 2001, we acquired the assets of CANPET
Energy Group Inc. ("CANPET") a Calgary based Canadian crude oil and liquefied
petroleum gas marketing company, for approximately $42.0 million plus excess
inventory at the closing date of approximately $25 million. Approximately $24.0
million of the purchase price, plus the excess inventory, was paid in cash at
closing and the remainder which is subject to certain performance standards will
be paid in common units in April, 2004, if such standards are met. CANPET
activities include gathering approximately 75,000 barrels per day of crude oil
and marketing approximately 26,000 barrels per day of natural gas liquids.
Tangible assets include a crude oil handling facility, a 130,000-barrel tank
facility and working capital of approximately $8.6 million. Financing for the
acquisition was provided through borrowings under our bank credit facility.
Results of Operations
Three Months Ended June 30, 2001 and 2000
For the three months ended June 30, 2001, we reported net income of $7.1
million on total revenue of $1.6 billion compared to net income for the same
period in 2000 of $6.1 million on total revenues of $1.5 billion. The results
for the three months ended June 30, 2001 and 2000 include the following unusual
items:
2001
. a $6.0 million charge associated with the vesting of phantom partnership
units as a result of the sale by our former general partner of a portion
of its general partner interest. $5.6 million of the charge was noncash
and was satisfied by units owned by our former general partner. This
portion of the charge had no impact on equity or the number of
outstanding units as it was offset by a deemed capital contribution by
our former general partner and the units were satisfied by units owned
by our former general partner.
2000
. an extraordinary loss of $11.0 million related to the refinancing of our
credit agreements, and
. $2.9 million of previously deferred gains on interest rate swap
terminations recognized due to the early extinguishment of debt.
Excluding these unusual items, we would have reported net income of $13.1
million and $14.2 million for the three months ended June 30, 2001 and 2000,
respectively.
The following table sets forth our operating results for the periods
indicated and includes the impact of these unusual items discussed above (in
thousands) (unaudited):
16
THREE MONTHS ENDED
JUNE 30,
---------------------
2001 2000
---- ----
OPERATING RESULTS:
Revenues $ 1,586,617 $ 1,481,834
=========== ===========
Gross margin:
Pipeline $ 18,699 $ 12,759
Gathering and marketing
and terminalling and storage 17,688 20,015
----------- -----------
Total 36,387 32,774
General and administrative expense (15,041) (7,949)
----------- -----------
Gross profit $ 21,346 $ 24,825
=========== ===========
Net income $ 7,067 $ 6,061
=========== ===========
AVERAGE DAILY VOLUMES (BARRELS):
Pipeline Activities:
All American
Tariff activities 68 74
Margin activities 56 57
Canada 210 -
Other 152 118
----------- -----------
Total 486 249
=========== ===========
Lease gathering 322 237
Bulk purchases 17 26
----------- -----------
Total 339 263
=========== ===========
Terminal throughput 151 61
=========== ===========
Storage leased to third parties,
monthly average volumes 2,427 1,953
=========== ===========
Revenues. Revenues increased to $1.59 billion for the second quarter of
2001 compared to the 2000 second quarter amount of $1.48 billion. The increase
is primarily attributable to the Murphy Acquisition. The impact on revenues from
the increase in volumes from the Murphy Acquisition, as well as the increase in
our domestic lease volumes, were offset by lower crude oil prices.
Cost of Sales and Operations. Cost of sales and operations increased to
$1.55 billion in the second quarter of 2001 compared to $1.45 billion in the
same quarter of 2000, primarily due to the reasons discussed above under
"Revenues".
General and Administrative. General and administrative expenses were $15.0
million for the quarter ended June 30, 2001, compared to $7.9 million for the
second quarter in 2000. The increase in 2001 is predominantly due to a $5.6
million noncash charge and $0.4 million cash charge related to the vesting of
phantom partnership units, as well as expenses incurred as a result of the
Murphy Acquisition.
Depreciation and Amortization. Depreciation and amortization expense was
$6.5 million for the quarter ended June 30, 2001, compared to $4.7 million for
the second quarter of 2000. The majority of this increase is due to the Murphy
Acquisition.
Interest expense. Interest expense was $8.1 million for the quarter ended
June 30, 2001, compared to $6.2 million for the 2000 quarter. The increase is
primarily due to the increase in debt levels in the second quarter as a result
of the net effect of the Murphy Acquisition and the proceeds from the issuance
of common units as well as lower interest rates. Interest expense was
approximately $6.6 million in the first quarter of 2001.
Early extinguishment of debt. During the quarter ended June 30, 2000, we
recognized an extraordinary loss, consisting primarily of unamortized debt issue
costs totaling $11.0 related to the refinancing or our credit facilities. In
addition, interest and other income for the second quarter 2000 includes $2.9
million of previously deferred gains from terminated interest rate swaps as a
result of the debt extinguishment.
17
Segment Results
Pipeline Operations. Gross margin from pipeline operations increased 47% to
$18.7 million for the quarter ended June 30, 2001 from $12.8 million for the
prior year quarter. Increased margins from the Murphy Acquisition, a 10%
increase in the tariff rate on the All American Pipeline, as well as increased
volumes on the Scurlock and West Texas gathering systems were all contributing
factors in the increase. These increases were partially offset by increased fuel
and power expenses.
Average daily volumes on our pipelines during the second quarter of this
year were 486,000 barrels per day compared to 249,000 barrels per day last year.
The 237,000 barrel per day increase includes increases of 210,000 barrels per
day due to the Murphy Acquisition and 27,000 barrels per day on our existing
pipeline systems. Tariff transport volumes on the All American Pipeline
decreased from an average of 74,000 barrels per day for the quarter ended June
30, 2000 to 68,000 barrels per day in the comparable quarter of 2001, due to a
decrease in shipments of offshore California production.
Gathering and Marketing Activities and Terminalling and Storage Activities.
Gross margin from gathering, marketing, terminalling and storage activities was
approximately $17.7 million for the quarter ended June 30, 2001 compared to
$20.0 million in the prior year quarter. This decrease is due to tightened
margins as a result of a contango market as well as increased operating costs
related to higher fuel and power costs. Incremental margins from the Murphy
Acquisition partially offset the decreases discussed above.
Total gathering volumes increased from an average of 263,000 barrels per
day in the second quarter of 2000 to approximately 339,000 barrels per day in
the current year period. Approximately half of this increase is due to the
Murphy Acquisition with the remainder coming from an acquisition of certain
facilities from Placid Oil Company in December 2000, as well as increases from
our existing domestic business units. Terminal throughput averaged approximately
151,000 barrels per day and 61,000 barrels per day in the first quarter of 2001
and 2000, respectively, primarily due to throughput arrangements with refiners
and the existence of a contango market.
Six Months Ended June 30, 2001 and 2000
For the six months ended June 30, 2001, we reported net income of $20.1
million on total revenue of $3.1 billion, compared to a net income for the same
period in 2000 of $66.2 million on total revenues of $3.5 billion. The results
for the six months ended June 30, 2001 and 2000 include the following unusual
items:
2001
. a $6.1 million charge associated with the vesting of phantom
partnership units primarily as a result of the sale by our former
general partner of a portion of its general partner interest. $5.7
million of the charge was noncash and was satisfied by units owned by
our former general partner. This portion of the charge had no impact on
equity or the number of outstanding units as it was offset by a deemed
capital contribution by our former general partner and the units were
satisfied by units owned by our former general partner, and
. $0.5 million cumulative effect gain as a result of the adoption of
Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities" ("SFAS 133").
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;
. $9.7 million of previously deferred gains on interest rate swap
terminations recognized due to the early extinguishment of debt;
. an extraordinary loss of $15.1 million related to the early
extinguishment of debt, and
. amortization of $4.6 million of debt issue costs associated with
facilities put in place during the fourth quarter of 1999.
Excluding these unusual items, we would have reported net income of $25.7
million and $28.1 million for the six months ended June 30, 2001 and 2000,
respectively.
The following table sets forth our operating results for the periods
indicated and includes the impact of the unusual items discussed above (in
thousands) (unaudited):
18
SIX MONTHS ENDED
JUNE 30,
2001 2000
---------------------
OPERATING RESULTS:
Revenues $ 3,106,741 $ 3,484,341
=========== ===========
Gross margin:
Pipeline $ 32,591 $ 25,914
Gathering and marketing
and terminalling and storage 36,526 43,412
----------- -----------
Total 69,117 69,326
General and administrative expense (24,030) (16,575)
----------- -----------
Gross profit $ 45,087 $ 52,751
=========== ===========
Net income $ 20,082 $ 66,216
=========== ===========
SIX MONTHS ENDED
JUNE 30,
2001 2000
---- ----
AVERAGE DAILY VOLUMES (BARRELS):
Pipeline Activities:
All American
Tariff activities 69 73
Margin activities 61 58
Canada(1) 210 -
Other 157 116
----- -----
Total 497 247
===== =====
Lease gathering 324 247
Bulk purchases 19 28
----- -----
Total 343 275
===== =====
Terminal throughput 143 55
===== =====
Storage leased to third parties,
monthly average volumes 2,165 1,387
===== =====
- --------
(1) Represents average daily volumes from the effective date, April 1, 2001.
Revenues. Revenues decreased to $3.11 billion from $3.48 billion in the
first half of 2000. The decrease is primarily attributable to lower crude oil
prices, offset somewhat by higher pipeline and gathering volumes, primarily
attributable to the Murphy Acquisition.
Cost of Sales and Operations. Cost of sales and operations decreased to
$3.04 billion from $3.42 billion in the first half of 2000, primarily due to the
reasons discussed above under "Revenues".
General and Administrative. General and administrative expenses were $24.0
million for the six months ended June 30, 2001, compared to $16.6 million for
the same period in 2000. The increase in 2001 is primarily due to a $6.1 million
charge attributable to the vesting of phantom partnership units in the second
quarter as a result of the sale by our former general partner of a portion of
its general partner interest. $5.7 million of the charge was noncash and was
satisfied by units owned by our former general partner. This portion of the
charge had no impact on partner's capital or the number of outstanding units as
it was offset by a deemed capital contribution by our former general partner.
Depreciation and Amortization. Depreciation and amortization expense was
$11.2 million for the six months ended June 30, 2001, compared to $14.8 million
for the first half of 2000. The decrease is primarily due to the increased
amortization of debt issue costs in the 2000 period associated with facilities
put in place during the fourth quarter of 1999 as a result of the unauthorized
trading losses and somewhat offset in the current year period by the
depreciation attributable to the Murphy Acquisition.
19
Interest expense. Interest expense was $14.7 million for the six months
ended June 30, 2001, compared to $15.3 million for the same period in 2000. The
decrease is due to a lower average debt balance as well as lower interest rates.
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 $15.1 million related to the permanent reduction of the All
American Pipeline, L.P. term loan facility and the refinancing of our credit
facilities. In addition, interest and other income for the six months ended
June 30, 2000, includes $9.7 million of previously deferred gains from
terminated interest rate swaps as a result of the debt extinguishments.
Cumulative effect of accounting change. During the first quarter of 2001,
we recognized a $0.5 million cumulative effect gain as a result of the adoption
of SFAS 133 effective January 1, 2001.
Segment Results
Pipeline Operations. Gross margin from pipeline operations increased to
$32.6 million for the six months ended June 30, 2001 compared to $25.9 million
for the prior year period. Increased margins from the Murphy Acquisition, a 10%
increase in the tariff rate on the All American Pipeline, as well as increased
volumes on the Scurlock gathering systems were all contributing factors in the
increase.
Average daily volumes on our pipelines during the first half of this year
were 497,000 barrels per day compared to 247,000 barrels per day last year. The
250,000 barrel per day increase includes increases of 210,000 barrels per day
due to the Murphy Acquisition and 40,000 barrels per day on our existing
pipeline systems. Tariff transport volumes on the All American Pipeline
decreased from an average of 73,000 barrels per day for the six months ended
June 30, 2000 to 69,000 barrels per day in the comparable period of 2001,
primarily due to a decrease in shipments of offshore California production.
Gathering and Marketing Activities and Terminalling and Storage Activities.
Gross margin from gathering, marketing, terminalling and storage activities was
approximately $36.5 million for the six months ended June 30, 2001 compared to
$43.4 million in the prior year period. This decrease is due to tightened
margins as a result of a contango crude market as well as increased operating
costs related to higher fuel and power costs. Incremental margins from the
Murphy Acquisition partially offset the decreases discussed above.
Total gathering volumes increased from an average of 275,000 barrels per
day in the first half of 2000 to approximately 343,000 barrels per day in the
current year period. Approximately half of this increase is due to the Murphy
Acquisition with the remainder coming from an acquisition of certain facilities
from Placid Oil Company in December 2000, as well as our existing domestic
business units. Terminal throughput averaged approximately 143,000 barrels per
day and 55,000 barrels per day in the first half of 2001 and 2000, respectively,
primarily due to throughput arrangements with refiners and the existence of a
contango market.
Liquidity and Capital Resources
Credit Agreements
In May 2001, we entered into new amended and restated credit facilities
that replaced our existing credit facilities. Our $500.0 million senior secured
revolving credit facility was replaced by a $630.0 million senior secured
revolving credit and term loan facility, which is secured by substantially all
of our assets. The facility consists of a $500.0 million domestic revolving
facility (with a $10.0 million letter of credit sublimit), a $30.0 million
Canadian revolving facility (with a $5.0 million letter of credit sublimit) and
a $100.0 million term loan. The facility matures, as to the aggregate $530.0
million domestic and Canadian revolver portions, in April, 2005 and, as to the
$100.0 million term portion, in May, 2006. We also amended our $200 million
senior secured letter of credit and borrowing facility. For a complete
discussion of our credit facilities, see Note 7 to the Consolidated Financial
Statements.
20
Liquidity
Cash generated from operations and our credit facilities are our primary
sources of liquidity. At June 30, 2001, we had working capital of approximately
$28.6 million. On August 8, 2001, subsequent to the closing of the CANPET
acquisition, PAA had approximately $439.8 million outstanding under its $630
million of credit facilities (excluding the letter of credit and borrowing
facility). Accordingly, PAA can borrow up to an additional $190 million subject
to covenants contained in the agreement.
We believe that we have sufficient liquid assets, cash from operations and
borrowing capacity under our credit agreements to meet our financial
commitments, debt service obligations, contingencies and anticipated capital
expenditures.
Cash Flows
SIX MONTHS ENDED
JUNE 30,
------------------
(IN MILLIONS) (UNAUDITED) 2001 2000
- ------------------------ ---- ----
Cash provided by (used in):
Operating activities $ (47.0) $ (6.4)
Investing activities (168.9) 218.3
Financing activities 213.5 (264.1)
Operating Activities. Net cash used in operating activities for the first
half of 2001 resulted primarily from purchases of hedged inventory maintained in
storage until delivery due to the existence of a contango market. All of this
inventory was hedged for delivery in the third quarter.
Investing Activities. Net cash used for investing activities for the first
half of 2001 included approximately $161 million for the Murphy Acquisition.
Financing activities. Cash provided by financing activities for the first
half of 2001 resulted from our credit facilities that were used to finance the
Murphy Acquisition and the issuance of additional units which raised
approximately $100.7 million of equity capital. Proceeds from the equity
offering were used to repay indebtedness under the credit facilities.
Contingencies
Following our announcement in November 1999 of our losses resulting from
unauthorized trading by a former employee, numerous class action lawsuits were
filed in the United States District Court of the Southern District of Texas
against us, certain of our general partner's officers and directors and in some
of these cases, our general partner and Plains Resources Inc. alleging
violations of the federal securities laws. In addition, derivative lawsuits
were filed in the Delaware Chancery Court and the United States District Court
of the Southern District of Texas against our general partner, its directors and
certain of its officers alleging the defendants breached the fiduciary duties
owed to us and our unitholders by failing to monitor properly the activities of
our traders. The class actions and the Delaware derivative suits have been
settled, subject to court approval. See Part II, Item 1 - "Legal Proceedings".
We may experience future releases of crude oil into the environment from
our pipeline and storage operations, or discover releases that were previously
unidentified. Although we maintain an extensive inspection program designed to
prevent and, as applicable, to detect and address such releases promptly,
damages and liabilities incurred due to any future environmental releases from
our assets may substantially affect our business.
Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statements of Financial Accounting Standards No. 141 "Business Combinations"
("SFAS 141") and No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142").
SFAS 141 requires all business combinations initiated after June 30, 2001, to be
accounted for under the purchase method. For all business combinations for
which the date of acquisition is after June 30, 2001, this Standard also
establishes specific criteria for the recognition of intangible assets
separately from goodwill and requires unallocated negative goodwill to be
written off immediately as an extraordinary gain, rather than deferred and
amortized. SFAS 142 changes the accounting for goodwill and other intangible
assets after an acquisition. The most significant changes made by SFAS 142 are:
1) goodwill and intangible assets with indefinite lives will no longer be
amortized; 2) goodwill and intangible assets with indefinite lives must
21
be tested for impairment at least annually; and 3) the amortization period for
intangible assets with finite lives will no longer be limited to forty years. At
this time, we cannot reasonably estimate the effect of the adoption of this
statement on either our financial position, results of operations, or cash
flows.
We will account for all future business combinations, including the CANPET
acquisition, under SFAS 141. Effective January 1, 2002, we will adopt SFAS 142,
as required. At that time, amortization will cease on the unamortized portion
of the goodwill arising from the Scurlock acquisition.
In June 2001, the FASB also approved for issuance SFAS 143 "Asset
Retirement Obligations". SFAS 143 establishes accounting requirements for
retirement obligations associated with tangible long-lived assets, including (1)
the timing of the liability recognition, (2) initial measurement of the
liability, (3) allocation of asset retirement cost to expense, (4) subsequent
measurement of the liability and (5) financial statement disclosures. SFAS 143
requires that an asset retirement cost should be capitalized as part of the cost
of the related long-lived asset and subsequently allocated to expense using a
systematic and rational method. We will adopt the statement effective
January 1, 2003, as required. The transition adjustment resulting from the
adoption of SFAS 143 will be reported as a cumulative effect of a change in
accounting principle. At this time, we cannot reasonably estimate the effect of
the adoption of this statement on either our financial position, results of
operations, or cash flows.
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 and those of our
general partner 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:
. the availability of adequate supplies of and demand for crude oil in the
areas in which we operate;
. the impact of crude oil price fluctuations; successful third-party
drilling efforts and completion of announced oil-sands project ;
. the effects of competition;
. the success of our risk management activities;
. the availability of favorable acquisition or combination opportunities;
our ability to receive credit on satisfactory terms
. unanticipated shortages or cost increases of power supplies, materials or
labor
. weather interference with business operations or project construction
. successful integration and future performance of recently acquired
assets;
. the impact of current and future laws and governmental regulations;
. environmental liabilities not covered by 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
the results anticipated in the forward-looking statements. Except as required by
applicable securities laws, we do not intend to update these forward-looking
statements and information.
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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 such 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.
On January 1, 2001, we adopted SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138. Under
SFAS 133, all derivative instruments are recorded on the balance sheet at fair
value. If the derivative does not qualify as a hedge or is not designated as a
hedge, the gain or loss on the derivative is recognized currently in earnings.
To qualify for hedge accounting, the derivative must qualify either as a fair
value hedge, cash flow hedge or foreign currency hedge. As of June 30, 2001, our
transactions consisted of only cash flow and foreign currency hedges (which are
defined as fair value hedges) and the remaining discussion will relate
exclusively to these types of derivative instruments. If the derivative
qualifies for cash flow hedge accounting, the gain or loss on the derivative is
deferred in accumulated Other Comprehensive Income ("OCI"), a component of
Partners' Capital, to the extent the hedge is effective. Fair value hedge gains
or losses are taken directly to earnings in the current period.
We utilize various derivative instruments, for purposes other than trading,
to hedge our exposure to price fluctuations on crude in storage and expected
purchases, sales and transportation of crude oil. The derivative instruments
consist primarily of futures and option contracts traded on the New York
Mercantile Exchange. We also utilize interest rate collars to manage the
interest rate exposure on our long-term debt and foreign currency hedges to
manage exchange rate exposure.
At June 30, 2001, a $5.8 million unrealized loss was recorded to OCI
together with related assets and liabilities of $6.9 million and $12.9 million,
respectively. Earnings included a noncash gain of $0.2 million related to the
ineffective portion of our cash flow hedges as well as the gain/loss on our
fair value hedges, (included in revenues in the income statement). Our hedge-
related assets and liabilities are included in other current assets and other
current liabilities in the balance sheet.
As of June 30, 2001, the total amount of deferred net losses on derivative
instruments recorded in OCI are expected to be reclassified to earnings during
the next twelve-month period. At June 30, 2001 we had the following open crude
oil hedge positions:
2001 2002
------------------ -------------------
3rd Qtr 4th Qtr 1st Qtr 2nd Qtr
------- ------- ------- -------
Volume (bbls)
Short positions 812,000 - - -
Long positions - 762,000 132,000 250,000
Average price ($/bbl) $25.13 $26.84 $27.28 $25.56
At June 30, 2001, we had an interest rate collar arrangement to protect interest
rate fluctuations on a portion of our outstanding debt for an aggregate notional
principal amount of $125.0 million. This instrument is based on LIBOR rates and
provides for a floor of 6.1% and a ceiling of 8.0% with an expiration date of
August 2002.
We formally document all relationships between hedging instruments and
hedged items, as well as our risk management objectives and strategy for
undertaking the hedge. Hedge effectiveness is measured on a quarterly basis.
This process includes specific identification of the hedging instrument and the
hedge transaction, the nature of the risk being hedged and how the hedging
instrument's effectiveness will be assessed. Both at the inception of the hedge
and on an ongoing basis, we assess whether the derivatives that are used in
hedging transactions are highly effective in offsetting changes in cash flows of
hedged items. No amounts were excluded from the computation of hedge
effectiveness.
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PART II. OTHER INFORMATION
Items 1. LEGAL PROCEEDINGS
Texas Securities Litigation. On November 29, 1999, a class action lawsuit
was filed in the United States District Court for the Southern District of Texas
entitled Di Giacomo v. Plains All American Pipeline, L.P., et al. The suit
alleged that Plains All American and certain of the officers and directors of
Plains All American Inc. (our general partner at the time) 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 Plains All American Inc. and Plains Resources as
additional defendants. All of the federal securities claims have been
consolidated into two actions. The first consolidated action is that filed by
purchasers of Plains Resources' common stock and options, and is captioned
Koplovitz v. Plains Resources Inc., et al. The second consolidated action is
that filed by purchasers of our common units, and is captioned Di Giacomo v.
Plains All American Pipeline, L.P., et al. Plaintiffs alleged that the
defendants were liable for securities fraud violations under Rule 10b-5 and
Section 20(a) of the Securities Exchange Act of 1934 and for making false
registration statements under Sections 11 and 15 of the Securities Act of 1933.
We and Plains Resources reached an agreement with representatives for the
plaintiffs for the settlement of all of the class actions, and in January 2001,
we deposited approximately $30.0 million under the terms of the settlement
agreement. The total cost of the settlement to us and Plains Resources,
including interest and expenses and after insurance reimbursements, was $14.9
million. Of that amount, $1.0 million was allocated to Plains Resources by
agreement between special independent committees of the board of directors of
Plains All American Inc. and the board of directors of Plains Resources. The
settlement is subject to final approval by the court. The settlement agreement
does not affect the Texas Derivative Litigation and Delaware Derivative
Litigation described below.
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 Plains All American Inc., 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 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 Susser v.
Plains All American Inc. as the complaint in the consolidated action. A motion
to dismiss was filed on behalf of the defendants on August 11, 2000.
The plaintiffs in the Delaware derivative litigation seek that the
defendants
. account for all losses and damages allegedly sustained by Plains All
American from the unauthorized trading losses;
. establish and maintain effective internal controls ensuring that our
affiliates and persons responsible for our affairs do not engage in
wrongful practices detrimental to Plains All American;
. pay for the plaintiffs' costs and expenses in the litigation, including
reasonable attorneys' fees, accountants' fees and experts' fees; and
. provide the plaintiffs any additional relief as may be just and proper
under the circumstances.
We have reached an agreement in principle with the plaintiffs, subject to
approval by the Delaware court, to settle the Delaware litigation for
approximately $1.1 million.
Texas Derivative Litigation. On July 11, 2000, a derivative lawsuit was
filed in the United States District Court of the Southern District of Texas
entitled Fernandes v. Plains All American Inc., et al, naming Plains All
American Inc., 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 above. A motion to dismiss was filed on behalf
of the defendants on August 14, 2000.
We intend to vigorously defend the claims made in the Texas derivative
litigation. We believe that Delaware court approval of the settlement of the
Delaware derivative litigation will effectively preclude prosecution of the
Texas derivative litigation. However, there can be no assurance that we will be
successful in our defense or that this lawsuit will not have a material adverse
effect on our financial position or results of operation.
We, in the ordinary course of business, are a claimant and/or a defendant
in various other legal proceedings. Management does not believe that the outcome
of these other legal proceedings, individually and in the aggregate, will have a
materially adverse effect on our financial condition, results of operations or
cash flows.
24
Items 2, 3, 4 & 5 are not applicable and have been omitted.
Item 6 - Exhibits and Reports on Form 8-K
A. Exhibits
* 3.1 - Amendment 3 to the Second Amended and Restated Agreement of Limited Partnership of Plains All
American Pipeline, L.P. dated as of April 27, 2001.
3.2 - Amendment 4 to the Second Amended and Restated Agreement of Limited Partnership of Plains All
American Pipeline, L.P. dated as of June 27, 2001.
* 3.3 - Amendment No. 1 to the Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. dated as
of April 27, 2001.
* 3.4 - Amendment No. 1 to the Amended and Restated Agreement of Limited Partnership of All American Pipeline, L.P. dated
as of April 27, 2001.
3.5 - Amendment No. 2 to the Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. dated as
of June 27, 2001 (incorporated by reference to Exhibit 3.2 to Form 8-K filed July 10, 2001).
3.6 - Amendment No. 2 to the Amended and Restated Agreement of Limited Partnership of All American Pipeline, L.P. dated
as of June 27, 2001 (incorporated by reference to Exhibit 3.3 to Form 8-K filed July 10, 2001).
3.7 - Amended and Restated Limited Partnership Agreement of Plains AAP, L.P., dated as of June 8, 2001. (incorporated by
reference to Exhibit 3.1 to Form 8-K filed June 11, 2001).
3.8 - Amended and Restated Limited Liability Company Agreement of Plains All American GP, LLC dated as of June 8, 2001
(incorporated by reference to Exhibit 3.2 to Form 8-K filed June 11, 2001).
4.1 - Registration Rights Agreement, dated as of June 8, 2001, among Plains All American Pipeline, L.P., Sable Holdings,
L.P., E-Holdings III, L.P., KAFU Holdings, LP, PAA Management, L.P., Mark E. Strome, Strome Hedgecap Fund, L.P.,
John T. Raymond and Plains All American Inc. (incorporated by reference to Exhibit 4.1 to Form 8-K filed June 11,
2001).
10.1 - Contribution, Assignment and Amendment Agreement, dated as of June 27, 2001, among Plains All American Pipeline,
L.P., Plains Marketing, L.P., All American Pipeline, L.P., Plains AAP, L.P. Plains All American GP LLC and Plains
Marketing GP Inc.
10.2 - Contribution, Assignment and Amendment Agreement, dated as of June 8, 2001 among Plains All American Inc., Plains
AAP, L.P. and Plains All American GP LLC (incorporated by reference to Exhibit 10.1 to Form 8-K filed June 11,
2001).
10.3 - Separation Agreement, dated as of June 8, 2001 among Plains Resources Inc., Plains All American Inc., Plains All
American GP LLC, Plains AAP, L.P. and Plains All American Pipeline, L.P. (incorporated by reference to Exhibit
10.2 to Form 8-K filed June 11, 2001).
10.4 - Pension and Employee Benefits Assumption and Transition Agreement, dated as of June 8, 2001 among Plains Resources
Inc., Plains All American Inc. and Plains All American GP LLC (incorporated by reference to Exhibit 10.3 to
Form 8-K filed June 11, 2001).
* 10.6 - First Amendment to Amended and Restated Credit Agreement (Letter of Credit and Hedged Inventory Facility) dated as
of May 25, 2001 among Plains Marketing, L.P., All American Pipeline, L.P. and Plains All American Pipeline, L.P.
and Fleet National Bank and certain other lenders.
* 10.7 - Second Amendment to Amended and Restated Credit Agreement (Letter of Credit and Hedged Inventory Facility) dated
as of June 26, 2001 among Plains Marketing, L.P., All American Pipeline, L.P. and Plains All American Pipeline,
L.P. and Fleet National Bank and certain other lenders.
* 10.8 - First Amendment to Amended and Restated Credit Agreement (Revolving Credit Facility) dated as of May 25, 2001
among Plains Marketing, L.P., All American Pipeline, L.P. and Plains All American Pipeline, L.P., and
25
Fleet National Bank, The Toronto-Dominion Bank, PMC (Nova Scotia) Company, Plains Marketing Canada, L.P. and
certain other lenders.
* 10.9 - Second Amendment to Amended and Restated Credit Agreement (Revolving Credit Facility) dated as of June 26, 2001
among Plains Marketing, L.P., All American Pipeline, L.P. and Plains All American Pipeline, L.P., and Fleet
National Bank, The Toronto-Dominion Bank, PMC (Nova Scotia) Company, Plains Marketing Canada, L.P. and certain
other lenders.
- --------------
* Filed herewith
B. Reports on Form 8-K
A Current Report on Form 8-K was filed on July 10, 2001, in connection with
amendments to the Partnership's and the operating limited partnerships'
partnership agreements related to the restructuring of the general partner
ownership of the Partnership's principal operating subsidiary partnerships.
A Current Report on Form 8-K was filed on July 2, 2001, in connection with
the deferral of the private placement of Senior Notes.
A Current Report on Form 8-K was filed on June 27, 2001, in connection with
the restructuring of the general partner ownership of the Partnership's
principal operating subsidiary partnerships.
A Current Report on Form 8-K was filed on June 25, 2001, in connection with
the acquisition of properties for Murphy Oil Company, Ltd.
A Current Report on Form 8-K was filed on June 11, 2001, in connection with
the restructuring of the ownership of our general partner.
A Current Report on Form 8-K was filed on May 25, 2001, in connection with
a proposed private placement of Senior Notes.
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 ALL AMERICAN PIPELINE, L.P.
By: PLAINS ALL AMERICAN GP LLC
Its General Partner
Date: August 14, 2001 By: /s/PHILLIP D. KRAMER
-------------------------------
Phillip D. Kramer, Executive Vice
President and Chief Financial Officer
26