Back to GetFilings.com
================================================================================
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, 2002
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 (I.R.S. Employer
jurisdiction of Identification No.)
incorporation or
organization)
333 Clay Street, Suite 1600
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 5, 2002, there were outstanding 31,915,939 Common Units, 1,307,190
Class B Common Units and 10,029,619 Subordinated Units.
================================================================================
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
TABLE OF CONTENTS
Page
----
PART I. FINANCIAL INFORMATION
CONSOLIDATED FINANCIAL STATEMENTS:
Consolidated Balance Sheets:
June 30, 2002, and December 31, 2001......................................... 3
Consolidated Statements of Operations:
For the three and six months ended June 30, 2002 and 2001.................... 4
Consolidated Statements of Cash Flows:
For the six months ended June 30, 2002 and 2001.............................. 5
Consolidated Statement of Partners' Capital:
For the six months ended June 30, 2002....................................... 6
Consolidated Statements of Comprehensive Income and Changes in Accumulated Other
Comprehensive Income:
For the three and six months ended June 30, 2002 and 2001.................... 7
Notes to Consolidated Financial Statements...................................... 8
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS................................................................. 16
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS..................... 27
PART II. OTHER INFORMATION...................................................... 29
2
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
June 30, December 31,
2002 2001
----------- ------------
(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents............................................. $ 5,792 $ 3,511
Accounts receivable and other current assets.......................... 514,034 365,697
Inventory............................................................. 67,289 188,874
---------- ----------
Total current assets.............................................. 587,115 558,082
---------- ----------
PROPERTY AND EQUIPMENT................................................... 685,636 653,050
Less allowance for depreciation and amortization...................... (60,320) (48,131)
---------- ----------
625,316 604,919
---------- ----------
OTHER ASSETS
Pipeline linefill..................................................... 58,242 57,367
Other, net............................................................ 67,331 40,883
---------- ----------
125,573 98,250
---------- ----------
$1,338,004 $1,261,251
========== ==========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable and other current liabilities........................ $ 476,675 $ 386,993
Due to affiliates..................................................... 19,170 13,685
Short-term debt....................................................... 57,847 104,482
---------- ----------
Total current liabilities......................................... 553,692 505,160
LONG-TERM LIABILITIES
Bank debt............................................................. 381,591 351,677
Other long-term liabilities........................................... 4,785 1,617
---------- ----------
Total liabilities................................................. 940,068 858,454
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 8)
PARTNERS' CAPITAL
Common unitholders (31,915,939 units outstanding at each date)........ 405,031 408,562
Class B common unitholders (1,307,190 units outstanding at each date). 19,389 19,534
Subordinated unitholders (10,029,619 units outstanding at each date).. (40,005) (38,891)
General partner....................................................... 13,521 13,592
---------- ----------
Total partners' capital........................................... 397,936 402,797
---------- ----------
$1,338,004 $1,261,251
========== ==========
See notes to consolidated financial statements.
3
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ----------------------
2002 2001 2002 2001
---------- ---------- ---------- ----------
(unaudited)
REVENUES......................................... $1,985,347 $1,586,617 $3,530,670 $3,106,741
COST OF SALES AND OPERATIONS..................... 1,943,640 1,550,230 3,450,575 3,037,624
---------- ---------- ---------- ----------
Gross Margin.................................. 41,707 36,387 80,095 69,117
---------- ---------- ---------- ----------
EXPENSES
General and administrative.................... 11,119 15,041 21,877 24,030
Depreciation and amortization................. 7,177 6,503 14,144 11,173
---------- ---------- ---------- ----------
Total expenses............................ 18,296 21,544 36,021 35,203
---------- ---------- ---------- ----------
OPERATING INCOME................................. 23,411 14,843 44,074 33,914
Interest expense.............................. (6,354) (8,101) (12,807) (14,707)
Interest and other income (expense)........... (106) 325 (35) 367
---------- ---------- ---------- ----------
Income before cumulative effect of accounting
change...................................... 16,951 7,067 31,232 19,574
Cumulative effect of accounting change........ -- -- -- 508
---------- ---------- ---------- ----------
NET INCOME....................................... $ 16,951 $ 7,067 $ 31,232 $ 20,082
========== ========== ========== ==========
NET INCOME--LIMITED PARTNERS..................... $ 15,902 $ 6,794 $ 29,356 $ 19,483
========== ========== ========== ==========
NET INCOME--GENERAL PARTNER...................... $ 1,049 $ 273 $ 1,876 $ 599
========== ========== ========== ==========
BASIC AND DILUTED NET INCOME PER
LIMITED PARTNER UNIT
Income before cumulative effect of accounting
change...................................... $ 0.37 $ 0.19 $ 0.68 $ 0.54
Cumulative effect of accounting change........ -- -- -- 0.02
---------- ---------- ---------- ----------
Net income................................ $ 0.37 $ 0.19 $ 0.68 $ 0.56
========== ========== ========== ==========
WEIGHTED AVERAGE UNITS OUTSTANDING............... 43,253 35,685 43,253 35,039
========== ========== ========== ==========
See notes to consolidated financial statements.
4
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Six Months Ended June 30,
------------------------
2002 2001
--------- -----------
(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income....................................................................... $ 31,232 $ 20,082
Adjustments to reconcile net income to net cash provided by (used in) operating
activities:
Depreciation and amortization................................................. 14,144 11,173
Cumulative effect of accounting change........................................ -- (508)
Change in derivative fair value............................................... 1,718 (62)
Noncash compensation expense.................................................. -- 5,741
Change in assets and liabilities, net of assets acquired and liabilities assumed:
Accounts receivable and other................................................. (139,534) (84,763)
Inventory..................................................................... 122,599 (77,119)
Accounts payable and other current liabilities................................ 82,214 81,424
Due to affiliates............................................................. 5,485 (2,947)
--------- -----------
Net cash provided by (used in) operating activities....................... 117,858 (46,979)
--------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment.............................................. (20,847) (9,412)
Proceeds from sales of assets.................................................... 987 1,077
Cash paid in connection with acquisitions........................................ (30,279) (160,584)
--------- -----------
Net cash used in investing activities..................................... (50,139) (168,919)
--------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt..................................................... 548,749 1,114,780
Proceeds from short-term debt.................................................... 248,247 193,150
Principal payments of long-term debt............................................. (512,989) (1,061,200)
Principal payments of short-term debt............................................ (301,882) (98,345)
Costs incurred in connection with financing arrangements......................... (654) (7,972)
Proceeds from issuance of units.................................................. -- 106,209
Distributions to unitholders and general partners................................ (47,041) (33,096)
--------- -----------
Net cash provided by (used in) financing activities....................... (65,570) 213,526
--------- -----------
Effect of translation adjustment on cash......................................... 132 --
Net increase (decrease) in cash and cash equivalents............................. 2,281 (2,372)
Cash and cash equivalents, beginning of period................................... 3,511 3,426
--------- -----------
Cash and cash equivalents, end of period......................................... $ 5,792 $ 1,054
--------- -----------
See notes to consolidated financial statements.
5
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
(in thousands)
Class B
Common Units Common Units Subordinated Units General Total
--------------- ------------- ----------------- Partner Partners'
Units Amount Units Amount Units Amount Amount Amount
------ -------- ----- ------- ------ -------- ------- ---------
(unaudited)
Balance at December 31, 2001 31,916 $408,562 1,307 $19,534 10,030 $(38,891) $13,592 $402,797
Distributions............... -- (33,113) -- (1,356) -- (10,406) (2,166) (47,041)
Other comprehensive income.. -- 7,594 -- 311 -- 2,385 658 10,948
Net income.................. -- 21,664 -- 887 -- 6,805 1,876 31,232
------ -------- ----- ------- ------ -------- ------- --------
Balance at June 30, 2002.... 31,916 $404,707 1,307 $19,376 10,030 $(40,107) $13,960 $397,936
====== ======== ===== ======= ====== ======== ======= ========
See notes to consolidated financial statements.
6
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND
CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME
(in thousands)
Statements of Comprehensive Income
Three Months Ended Six Months Ended
June 30, June 30,
----------------- ---------------
2002 2001 2002 2001
------- ------- ------- -------
(unaudited)
Net Income................ $16,951 $ 7,067 $31,232 $20,082
Other comprehensive income 13,899 (3,183) 10,948 (5,838)
------- ------- ------- -------
Total comprehensive income $30,850 $ 3,884 $42,180 $14,244
======= ======= ======= =======
Statement of Accumulated Other Comprehensive Income
Net
deferred
loss on Currency
derivative translation
instruments adjustments Total
----------- ----------- --------
(unaudited)
Beginning Balance at December 31, 2001.......................... $(4,740) $(8,002) $(12,742)
Current year activity
Reclassification adjustments for settled contracts....... 795 -- 795
Changes in fair value of outstanding hedge positions..... 121 -- 121
Currency translation adjustment.......................... -- 10,032 10,032
------- ------- --------
Total current year activity.................................. 916 10,032 10,948
------- ------- --------
Ending Balance at June 30, 2002................................. $(3,824) $ 2,030 $ (1,794)
======= ======= ========
See notes to consolidated financial statements.
7
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 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. The terms
"Plains All American" and the "Partnership" herein refer to Plains All American
Pipeline, L.P. and its affiliated operating partnerships. 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 and liquefied petroleum
gas ("LPG"). Our operations are conducted primarily in Texas, California,
Oklahoma, Louisiana and the Canadian provinces of Alberta, Saskatchewan and
Manitoba.
The accompanying financial statements and related notes present our
consolidated financial position as of June 30, 2002, and December 31, 2001, the
results of our operations for the three and six months ended June 30, 2002 and
2001, cash flows for the six months ended June 30, 2002 and 2001, changes in
partners' capital for the six months ended June 30, 2002, total other
comprehensive income for the three and six months ended June 30, 2002 and 2001,
and accumulated other comprehensive income for the six months ended June 30,
2002. The financial statements have been prepared in accordance with the
instructions to interim reporting as prescribed by the Securities and Exchange
Commission. 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. When necessary, certain
reclassifications are made to prior period amounts to conform to current period
presentation. The results of operations for the three and six months ended June
30, 2002, 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
2001 Annual Report on Form 10-K.
Note 2--Derivative Instruments and Hedging Activities
We utilize various derivative instruments, for purposes other than trading,
to hedge our exposure to price fluctuations with respect to crude oil and
liquefied petroleum gas in storage and expected purchases, sales and
transportation of those commodities. The derivative instruments consist
primarily of futures and option contracts traded on the New York Mercantile
Exchange and over-the-counter transactions, including crude oil swap contracts
entered into with financial institutions and other counterparties. We also
utilize interest rate and foreign exchange swaps and collars to manage the
interest rate exposure on our long-term debt and foreign exchange exposure
arising from our Canadian operations. All of the interest rate and foreign
exchange instruments utilized are placed with large creditworthy financial
institutions.
In accordance with Statement of Financial Accounting Standards ("SFAS") No.
133 "Accounting for Derivative Instruments and Hedging Activities," gains and
losses on derivative instruments are deferred to Other Comprehensive Income
("OCI") and are included in revenues in the period that the related volumes are
delivered. Gains and losses on hedging instruments, which do not qualify for
hedge accounting or which represent hedge ineffectiveness and changes in the
time value component of the fair value, are included in earnings in the current
period.
The June 30, 2002, balance sheet includes a $3.8 million unrealized loss in
OCI and related assets and liabilities of $6.7 million ($5.8 million current)
and $11.5 million ($8.4 million current), respectively. Earnings for the six
months ended June 30, 2002, included a noncash loss of $1.7 million related to
the ineffective portion of our cash flow hedges, and certain derivative
contracts that did not qualify as hedges due to a low correlation between the
futures contract and hedged item (a $1.0 million noncash loss net of the
reversal of the prior period
8
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
fair value adjustment related to contracts that settled during the current
period). Our hedge-related assets and liabilities are included in other current
and non-current assets and liabilities in the consolidated balance sheet.
As of June 30, 2002, the total amount of deferred net losses on derivative
instruments recorded in OCI are expected to be reclassified to earnings during
2002, 2003 and 2004. Of the amounts deferred to OCI, a loss of $1.1 million
will be reclassified from OCI to earnings in the next twelve months.
Interest rate swaps and collars are used to hedge underlying interest
obligations. These instruments hedge interest rates on 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, 2002, we had interest rate swap and collar arrangements for an aggregate
notional principal amount of $275.0 million. These instruments are based on
LIBOR rates. The collar provides for a floor of 6.1% and a ceiling of 8.0% with
an expiration date of August 19, 2002, for a $125.0 million notional principal
amount. The fixed rate swaps provide for a rate of 3.6% for a $100.0 million
notional principal amount expiring September 2003, and a rate of 4.3% for a
$50.0 million notional principal amount expiring March 2004.
Because substantially all of our Canadian business is conducted in Canadian
dollars (CAD), we use certain financial instruments to minimize the risks of
changes in the exchange rate. These instruments include forward exchange
contracts, forward extra option contracts and cross currency swaps. At June 30,
2002, we had forward exchange contracts and forward extra option contracts that
allow us to exchange $3.0 million Canadian for at least $1.9 million U. S.
quarterly during 2002 and 2003 (based on a Canadian-U.S. dollar exchange rate
of 1.54). At June 30, 2002, we also had a cross currency swap contract for an
aggregate notional principal amount of $24.8 million, effectively converting
this amount of our $99.0 million senior secured term loan (25% of the total)
from U.S. dollars to $38.3 million of Canadian dollar debt (based on a
Canadian-U.S. dollar exchange rate of 1.55). The terms of this contract mirror
the term loan, matching the amortization schedule and final maturity in May
2006. Additionally, at June 30, 2002, $13.2 million of our long-term debt was
denominated in Canadian dollars ($20.0 million CAD based on a Canadian-U.S.
dollar exchange rate of 1.52).
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
hedged 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.
Note 3--Acquisitions
Shell's West Texas Interests
In May 2002, we entered into a definitive purchase and sale agreement to
purchase certain businesses from Shell Pipeline Company, including its
interests in the Basin Pipeline System, the Rancho Pipeline System and the
Permian Basin Gathering System, for approximately $315.0 million, excluding
financing and related transaction costs. At execution, we deposited $15.7
million into an escrow account. This transaction was consummated on August 1,
2002, using proceeds from our revolving credit facilities. Net of interest
earned on the deposit, approximately $9.1 million related to the settlement of
pre-existing accounts receivable and inventory balances and purchase price
adjustments as provided for in the amended purchase and sale agreement, the
final amount paid to Shell at closing totaled approximately $288.2 million
cash. Including approximately $9.6 million of estimated transaction and closing
costs, the total purchase price is approximately $322.7 million.
9
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Coast/Lantern Acquisition
In March 2002, we completed the acquisition of substantially all of the
domestic crude oil pipeline, gathering, and marketing assets of Coast Energy
Group and Lantern Petroleum, divisions of Cornerstone Propane Partners, L.P.,
for approximately $7.6 million in cash, including the deposit of $2.5 million
made in December 2001, net of liabilities assumed and including transaction
costs. The principal assets acquired, which are located in West Texas, include
several gathering lines, crude oil contracts and a small truck and trailer
fleet. This acquisition did not have a material effect on either our financial
position, results of operations or cash flows.
Butte Acquisition
In February 2002, we acquired an approximate 22% equity interest in Butte
Pipe Line Company from Murphy Ventures, a subsidiary of Murphy Oil Corporation.
The total cost of the acquisition, including various transaction and related
expenses, was approximately $8.0 million. Butte Pipe Line Company owns the
373-mile Butte Pipeline System that runs from Baker, Montana, to Guernsey,
Wyoming. The remaining 78% interest in the Butte Pipe Line Company is owned by
Equilon Pipeline Company LLC. This acquisition did not have a material effect
on either our financial position, results of operations or cash flows.
Note 4--Credit Agreements
As amended, our credit facilities consist of a $350.0 million senior secured
letter of credit and hedged inventory facility (with current lender commitments
totaling $200.0 million), and a $779.0 million senior secured revolving credit
and term loan facility, each of which is secured by substantially all of our
assets. The revolving credit and term loan facility consists of a $450.0
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), a $99.0 million term loan, and a $200.0 million
term B loan. The facilities have final maturities as follows:
. as to the $350.0 million senior secured letter of credit and hedged
inventory facility, in April 2005;
. as to the aggregate $480.0 million domestic and Canadian revolver
portions, in April 2005;
. as to the $99.0 million term loan, in May 2006; and
. as to the $200.0 million term B loan, in September 2007.
In July 2002, we amended our credit facilities to enable us to consummate
the pending acquisition of certain businesses from Shell Pipeline Company and
to accommodate the increased activity level associated with the expanded asset
base, while preserving our ability to pursue additional acquisitions. The
amended facilities enable us to expand the size of the letter of credit and
hedged inventory facility from $200.0 million to $350.0 million without
additional approval from existing lenders. As amended, the financial covenants
require us to maintain:
. a current ratio (as defined) of at least 1.0 to 1.0;
. a debt coverage ratio which will not be greater than: (i) 5.0 to 1.0
through and including March 30, 2003, and 4.0 to 1.0 thereafter; and (ii)
5.25 to 1.0 on and after our issuing at least $150.0 million of unsecured
debt and, in addition, our secured debt coverage ratio will not be
greater than 4.0 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 0.7 to 1.0 through March 30,
2003, and .65 to 1.0 at any time thereafter.
For covenant compliance purposes, letters of credit and borrowings under the
letter of credit and hedged inventory facility are excluded when calculating
the debt coverage ratio.
10
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The amended facility also permits us to issue up to $400 million of
unsecured debt having a maturity beyond the final maturity of the existing
credit facility. Upon the issuance of unsecured debt, the amount of the $450
million domestic revolving facility is reduced by an amount equal to the
following: i) 40% of the face amount of the unsecured debt issued if the face
amount is less than $350 million, less $50 million, or ii) 50% of the face
amount of the unsecured debt issued if the face amount is equal to or greater
than $350 million, less $50 million. In anticipation of a potential issuance of
senior unsecured notes during the third quarter, we entered into a sixty day
treasury lock on a $100 million principal amount with a base index rate of
4.37% and an all in basis at maturity of 4.47%.
Note 5--Distributions
On July 23, 2002, we declared a cash distribution of $0.5375 per unit on our
outstanding common units, Class B common units and subordinated units. The
distribution is payable on August 14, 2002, to unitholders of record on August
5, 2002, for the period April 1, 2002, through June 30, 2002. The total
distribution to be paid is approximately $24.6 million, with approximately
$17.8 million to be paid to our common unitholders, $5.4 million to be paid to
our subordinated unitholders and $1.4 million to be paid to our general partner
for its general partner and incentive distribution interests. The distribution
is in excess of the minimum quarterly distribution specified in the Partnership
Agreement.
On May 15, 2002, we paid a cash distribution of $0.525 per unit on our
outstanding common units, Class B common units and subordinated units. The
distribution was paid to unitholders of record on May 6, 2002, for the period
January 1, 2002, through March 31, 2002. The total distribution paid was
approximately $23.9 million, with approximately $17.4 million paid to our
common unitholders, $5.3 million paid to our subordinated unitholders and $1.2
million paid to our general partner for its general partner and incentive
distribution interests. The distribution was in excess of the minimum quarterly
distribution specified in the Partnership Agreement.
Note 6--Recent Disruptions in Industry Credit Markets
As a result of business failures, revelations of material misrepresentations
and related financial restatements by several large, well-known companies in
various industries over the last nine months, there have been significant
disruptions and extreme volatility in the financial markets and credit markets.
Because of the credit intensive nature of the energy industry and troubling
disclosures by several large, diversified energy companies, the energy industry
has been especially impacted by these developments, with the rating agencies
downgrading a number of large, energy related companies. Accordingly, in this
environment we are exposed to an increased level of direct and indirect
counter-party credit and performance risk.
The majority of our credit extensions and therefore our accounts receivable
relate to our gathering and marketing activities that can generally be
described as high volume and low margin activities, in many cases involving
complex exchanges of crude oil volumes. In transacting business with our
counter-parties, we must determine the amount, if any, of open credit lines to
extend to our counter-parties and the form and amount of financial performance
assurances we may require. The vast majority of such accounts receivable settle
monthly and any collection delays generally involve discrepancies or disputes
as to the appropriate price, volumes or quality of crude oil delivered or
exchanged and associated billing delays. Of our $358 million aggregate
receivables balance included in current assets at December 31, 2001,
approximately $331 million, or 93%, were less than 60 days past the scheduled
invoice date. Of our $499 million aggregate receivables balance included in
current assets at June 30, 2002, approximately $489 million, or 98%, were less
than 60 days past the scheduled invoice date.
We have modified our credit arrangements with certain counter-parties that
have been adversely affected by these recent events, but a large portion of the
balances more than 60 days past the invoice date, along with
11
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
approximately $10.8 million of net receivables classified as long-term, are
associated with an ongoing effort to bring substantially all balances to within
sixty days of scheduled invoice date. In certain cases, this effort involves
reconciling and resolving certain discrepancies, generally related to pricing,
volumes, quality or crude oil exchange imbalances and the majority of these
receivables are related to the period immediately following the disclosure of
our unauthorized trading losses in late 1999. Following that disclosure, a
significant number of our suppliers and trading partners temporarily reduced or
eliminated our open credit and demanded payments or withheld payments due us
before disputed amounts or discrepancies associated with exchange imbalances,
pricing issues and quality adjustments were reconciled in accordance with
customary industry practices. Because these matters also arose in the midst of
various software systems conversions and acquisition integration activities,
our effort to resolve outstanding claims and discrepancies has included
reprocessing and integrating historical information on numerous software
platforms. We have made significant progress to date in this effort and intend
to substantially complete this project in the second half of 2002 and, based on
the work performed to date and the scope of the remaining work to be performed,
we believe these prior period balances are collectible and consider our
reserves adequate. However, in the event our counter-parties experience an
unanticipated deterioration in their credit-worthiness, any addition to
existing reserves or write-offs in excess of such reserves would result in a
noncash charge to earnings. We do not believe any such charge would have a
material effect on our cash flow or liquidity.
Note 7--Operating Segments
Our operations consist of two operating segments: (1) Pipeline
Operations--engages in interstate and intrastate crude oil pipeline
transportation and certain related merchant activities; (2) Gathering,
Marketing, Terminalling and Storage Operations--engages in purchases and
resales of crude oil and LPG at various points along the distribution chain and
the operation of certain terminalling and storage assets. We evaluate segment
performance based on gross margin and gross profit.
Gathering,
Marketing,
Terminalling
Pipeline & Storage Total
-------- ------------ ----------
(in thousands)
(unaudited)
Three Months Ended June 30, 2002
Revenues:
External Customers.......................... $111,471 $1,873,876 $1,985,347
Intersegment (a)............................ 3,687 -- 3,687
-------- ---------- ----------
Total revenues of reportable segments.... $115,158 $1,873,876 $1,989,034
======== ========== ==========
Segment gross margin (b)....................... $ 18,831 $ 22,876 $ 41,707
General and administrative expense............. (1,146) (9,973) (11,119)
-------- ---------- ----------
Segment gross profit (c)....................... $ 17,685 $ 12,903 $ 30,588
======== ========== ==========
Maintenance capital............................ $ 850 $ 112 $ 962
- ----------------------------------------------------------------------------------
(Table continued on following page)
12
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Gathering,
Marketing,
Terminalling
Pipeline & Storage Total
-------- ------------ ----------
(in thousands)
(unaudited)
Three Months Ended June 30, 2001
Revenues:
External Customers.......................... $ 91,815 $1,494,802 $1,586,617
Intersegment (a)............................ 5,166 -- 5,166
-------- ---------- ----------
Total revenues of reportable segments.... $ 96,981 $1,494,802 $1,591,783
======== ========== ==========
Segment gross margin (b)....................... $ 18,699 $ 17,688 $ 36,387
General and administrative expense............. (1,031) (8,390) (9,421)
-------- ---------- ----------
Segment gross profit (c)....................... $ 17,668 $ 9,298 $ 26,966
======== ========== ==========
Maintenance capital............................ $ -- $ 1,879 $ 1,879
- ----------------------------------------------------------------------------------
Six Months Ended June 30, 2002
Revenues:
External Customers.......................... $196,804 $3,333,866 $3,530,670
Intersegment (a)............................ 6,826 -- 6,826
-------- ---------- ----------
Total revenues of reportable segments.... $203,630 $3,333,866 $3,537,496
======== ========== ==========
Segment gross margin (b)....................... $ 37,285 $ 42,810 $ 80,095
General and administrative expense............. (2,089) (19,788) (21,877)
-------- ---------- ----------
Segment gross profit (c)....................... $ 35,196 $ 23,022 $ 58,218
======== ========== ==========
Maintenance capital............................ $ 2,220 $ 615 $ 2,835
- ----------------------------------------------------------------------------------
Six Months Ended June 30, 2001
Revenues:
External Customers.......................... $179,853 $2,926,888 $3,106,741
Intersegment (a)............................ 8,475 -- 8,475
-------- ---------- ----------
Total revenues of reportable segments.... $188,328 $2,926,888 $3,115,216
======== ========== ==========
Segment gross margin (b)....................... $ 32,591 $ 36,526 $ 69,117
General and administrative expense............. (1,491) (16,798) (18,289)
-------- ---------- ----------
Segment gross profit (c)....................... $ 31,100 $ 19,728 $ 50,828
======== ========== ==========
Maintenance capital............................ $ 104 $ 2,184 $ 2,288
- --------
a) Intersegment sales were conducted on terms believed to be consistent with
terms that would have been extended 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 gross margin less general and administrative
expenses, excluding noncash compensation expense as it is not allocated to
the reportable segments.
13
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Note 8--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 and
do not expect any additional expenditure to be material, 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 to determine the extent of the contamination. We have proposed
extending the scope of our study and are awaiting the state's response. We have
spent approximately $140,000 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.
We may experience future releases of crude oil into the environment from our
pipeline and storage operations, or discover past releases that were previously
unidentified. Although we maintain an inspection program designed to prevent
and, as applicable, to detect and address such releases promptly, damages and
liabilities incurred due to any such environmental releases from our assets may
substantially affect our business.
Litigation
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 our former general partner, its directors and certain of its officers as
defendants, and alleged 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. We reached an agreement in
principle with the plaintiffs to settle the Delaware litigation for
approximately $1.1 million. On March 6, 2002, the Delaware court approved the
settlement. The order became final in April of 2002 and the settlement amount
has been paid.
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 our former
general partner, its directors and certain of its officers as defendants. This
lawsuit contained the same claims and sought the same relief as the Delaware
derivative litigation, described above. We reached an agreement in principle
with the plaintiffs to settle the Texas litigation for approximately $112,500.
The court approved the settlement on March 18, 2002. The order became final in
April of 2002 and the settlement amount has been paid.
Other. We, in the ordinary course of business, are a claimant and/or a
defendant in various other legal proceedings. We do 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.
Note 9--Recent Accounting Pronouncements
In June 2002, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 146 "Accounting for Costs Associated with Exit or Disposal Activities".
SFAS 146 requires that a liability for a cost associated with an exit or
disposal activity be recognized when the liability is incurred rather than at
the date of the exit plan.
14
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
This Statement is effective for exit or disposal activities that are initiated
after December 31, 2002. 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.
In May 2002, the FASB issued SFAS 145 "Rescission of FASB Statements No. 4,
44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections as of
April 2002". SFAS 145 amends the treatment of gains and losses from the
extinquishment of debt only allowing those items that are truly unusual and
infrequent. The statement is effective for all transactions occurring after May
15, 2002. Effective with fiscal years beginning after May 15, 2002, any gain or
loss on extinguishment of debt that was classified as an extraordinary item in
prior periods presented that does not meet the criteria for classification as
an extraordinary item shall be reclassified. We do not believe that the
adoption of SFAS 145 will have a material effect on either our financial
position or cash flows, however, future extinguishments of debt may impact
income from continuing operations.
15
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
We are a Delaware limited partnership 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. The terms
"Plains All American" and the "Partnership" herein refer to Plains All American
Pipeline, L.P. and its affiliated operating partnerships. 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 and liquefied petroleum
gas. Our operations are conducted primarily in Texas, California, Oklahoma,
Louisiana and the Canadian provinces of Alberta, Saskatchewan and Manitoba and
consist of two operating segments: (1) Pipeline Operations and (2) Gathering,
Marketing, Terminalling and Storage Operations. We evaluate segment performance
based on gross margin and gross profit.
Pipeline Operations. Our activities from pipeline operations generally
consist of transporting third-party volumes of crude oil for a fee, third party
leases of pipeline capacity, barrel exchanges and buy/sell arrangements. We
also utilize our pipelines in our merchant activities conducted under our
gathering and marketing business. Tariffs and other fees on our pipeline
systems vary by receipt point and delivery point. The gross margin generated by
our tariff and other fee-related activities depends on the volumes transported
on the pipeline and the level of the tariff and other fees charged, as well as
the fixed and variable costs of operating the pipeline. Gross margin from our
pipeline capacity leases, barrel exchanges and buy/sell arrangements generally
reflect a negotiated amount.
Gathering, Marketing, Terminalling and Storage Operations. 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
margin businesses, and 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. Accordingly, an increase in
revenues is not necessarily an indication of a fundamental direction of the
segment's activities. Terminals are facilities where crude oil is transferred
to or from storage or a transportation system, such as a pipeline, to another
transportation system, such as trucks or another pipeline. The operation of
these facilities is called "terminalling". Gross margin from terminalling and
storage activities is dependent on the throughput volumes, the volume of crude
oil stored and the level of fees generated from our terminalling and storage
services.
Results of Operations
The following acquisitions impact the comparability of the 2002 and 2001
periods as noted in the discussion of the results of operations. In 2001, we
acquired substantially all of the Canadian crude oil pipeline, gathering,
marketing, terminalling and storage assets of Murphy Oil Company Ltd. and the
assets of CANPET Energy Group Inc. ("CANPET"), a Calgary-based Canadian crude
oil and liquefied petroleum gas marketing company, together the "Canadian
acquisitions". The acquisitions were effective April 1, 2001, and July 1, 2001,
respectively.
Three Months Ended June 30, 2002 and 2001
For the three months ended June 30, 2002, we reported net income of $17.0
million on total revenues of $1.99 billion compared to net income for the same
period in 2001 of $7.1 million on total revenues of $1.59 billion. When
evaluating net income, we exclude the impact of Statement of Financial
Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments
and Hedging Activities," resulting from derivative instruments that do not
qualify for hedge accounting or which represent hedge ineffectiveness. The
majority of
16
these instruments serve as economic hedges which offset future physical
positions not reflected in current results. Therefore, the SFAS 133 adjustment
to net income is not a complete depiction of the economic substance of the
transaction as it only represents the derivative side of these transactions and
does not take into account the offsetting physical position. In addition, the
impact will vary from quarter to quarter based on market prices at the end of
the quarter.
The following table reconciles our reported net income to our net income
before unusual or nonrecurring items and the impact of SFAS 133:
Three Months
Ended June 30,
------------
2002 2001
----- -----
(millions)
Reported net income.............................................. $17.0 $ 7.1
Noncash compensation expense..................................... -- 5.6
Noncash SFAS 133 gain............................................ (1.1) (0.2)
----- -----
Net income before unusual or nonrecurring items and the impact of
SFAS 133 (1)................................................... $15.8 $12.5
===== =====
- --------
(1) Numbers in table may not sum exactly due to rounding.
The following table sets forth our operating results for the periods
indicated and includes the impact of the items discussed above:
Three Months Ended
June 30,
------------------
2002 2001
-------- --------
Operating Results (in millions):
Revenues................................................... $1,985.3 $1,586.6
======== ========
Gross margin:
Pipeline................................................. 18.8 18.7
Gathering, marketing, terminalling and storage........... 22.9 17.7
-------- --------
Total................................................ 41.7 36.4
General and administrative expense......................... (11.1) (15.1)
-------- --------
Gross profit............................................... $ 30.6 $ 21.3
======== ========
Net income................................................. $ 17.0 $ 7.1
======== ========
Average Daily Volumes (thousands of barrels per day):
Pipeline segment:
Tariff activities
All American........................................... 61 68
Other domestic......................................... 151 152
Canada (1)............................................. 182 161
Margin activities........................................ 73 56
-------- --------
Total................................................ 467 437
======== ========
Gathering, marketing, terminalling and storage segment:
Lease gathering.......................................... 410 322
Bulk purchases........................................... 65 17
-------- --------
Total................................................ 475 339
======== ========
Terminal throughput (1).................................. 84 114
======== ========
Storage leased to third parties, monthly average volumes. 1,620 2,427
======== ========
- --------
(1) 2001 volume information is adjusted for consistency of comparison with 2002
presentation.
17
Revenues. Total revenues were $1.99 billion and $1.59 billion for the three
months ended June 30, 2002 and 2001, respectively. The increase is primarily
associated with higher gathering volumes primarily attributable to the
acquisition of the assets of CANPET in July of 2001. The average NYMEX price
for crude oil was $26.24 per barrel and $27.98 per barrel for the second
quarter of 2002 and 2001, respectively. For the three months ended June 30,
2002, we gathered from producers, using our assets or third-party assets,
approximately 410,000 barrels of crude oil per day. In addition, we purchased
in bulk, primarily at major trading locations, approximately 65,000 barrels of
crude oil per day. Our revenues reflect the sale of these barrels plus the sale
of additional barrels exchanged through buy/sell arrangements entered into to
enhance the margins of the gathered and bulk-purchased crude oil.
Cost of Sales and Operations. Cost of sales and operations were $1.94
billion and $1.55 billion in the second quarter of 2002 and 2001, respectively,
an increase of $0.39 million primarily due to the reasons discussed above with
respect to revenues.
General and Administrative. General and administrative expense ("G&A") was
$11.1 million for the quarter ended June 30, 2002, compared to $15.1 million
for the second quarter of 2001. Excluding the noncash compensation expense of
$5.6 million related to the vesting of phantom units, G&A for the second
quarter of 2001 would have been $9.4 million. The increase in 2002 is primarily
due to $2.5 million of expenses associated with our Canadian acquisitions,
partially offset by a decrease in other G&A expenses related to the domestic
operations.
Depreciation and Amortization. Depreciation and amortization expense was
$7.2 million for the quarter ended June 30, 2002, compared to $6.5 million for
the same period of 2001. The increase is primarily due to assets acquired and
other capital expansion projects.
Interest Expense. Interest expense decreased to $6.4 million for the quarter
ended June 30, 2002, from $8.1 million for the comparative 2001 period. The
decrease is due to the capitalization of $0.4 million of interest and lower
interest rates somewhat offset by a higher average debt balance and increased
commitment fees in the second quarter of 2002.
Segment Results
Pipeline Operations. Gross margin from pipeline operations increased to
$18.8 million for the quarter ended June 30, 2002, from $18.7 million for the
prior year quarter. Although total volumes increased, volumes transported from
Outer Continental Shelf ("OCS") production, which are our highest margin
barrels, declined. Therefore, gross margin did not increase in proportion to
the increase in volumes. Average daily volumes on our pipelines during the
second quarter of this year were 467,000 barrels per day compared to 437,000
barrels per day last year. Approximately 20,000 barrels per day of the increase
is due to increased volumes on our Canadian pipelines, 10,000 barrels per day
of which are due to the acquisition of the Wapella Pipeline in December 2001.
The remainder of the increase was primarily related to volumes on the Butte
Pipeline System acquired in February 2002, which were somewhat offset by a
decrease in OCS volumes.
Gathering, Marketing, Terminalling and Storage Operations. Gross margin from
gathering, marketing, terminalling and storage activities was approximately
$22.9 million for the quarter ended June 30, 2002, compared to $17.7 million in
the prior year quarter. Excluding the impact of the noncash fair value
adjustments related to SFAS 133, gross margin for this segment would have been
approximately $21.8 million for the quarter ended June 30, 2002, compared to
$17.5 million in the prior year quarter. The increase was primarily related to
our Canadian acquisitions.
Lease gathering volumes increased to approximately 410,000 barrels per day
in 2002 from an average of 322,000 barrels per day for the second quarter of
2001, mostly due to our Canadian acquisitions. Bulk purchase volumes increased
to approximately 65,000 barrels per day in the current period from
approximately 17,000 barrels per day for the second quarter of 2001. Lease
capacity decreased to an average of 1.6 million barrels per
18
month from an average of 2.4 million barrels per month in the prior year
quarter and terminal throughput averaged approximately 84,000 barrels per day
and 114,000 barrels per day in the second quarter of 2002 and 2001,
respectively. Both the third party lease volumes and terminal throughput
volumes are lower because we used more of our storage capacity for our contango
activities during this year's quarter.
Six Months Ended June 30, 2002 and 2001
For the six months ended June 30, 2002, we reported net income of $31.2
million on total revenues of $3.53 billion compared to net income for the same
period in 2001 of $20.1 million on total revenues of $3.11 billion. When
evaluating net income, we exclude the impact of SFAS 133 resulting from hedging
instruments that do not qualify for hedge accounting or which represent hedge
ineffectiveness. The majority of these instruments serve as economic hedges
which offset future physical positions not reflected in current results.
Therefore, the SFAS 133 adjustment to net income is not a complete depiction of
the economic substance of the transaction as it only represents the derivative
side of these transactions and does not take into account the offsetting
physical position. In addition, the impact will vary from quarter to quarter
based on market prices at the end of the quarter. The following table
reconciles our reported net income to our net income before unusual or
nonrecurring items and the impact of SFAS 133:
Six Months
Ended June 30,
-------------
2002 2001
----- -----
(millions)
Reported net income.............................................. $31.2 $20.1
Noncash compensation expense..................................... -- 5.7
Noncash cumulative effect of accounting change (1)............... -- (0.5)
Noncash SFAS 133 (gain) loss..................................... 1.7 (0.1)
----- -----
Net income before unusual or nonrecurring items and the impact of
SFAS 133 (2)................................................... $33.0 $25.2
===== =====
- --------
(1) Related to the adoption of SFAS 133 on January 1, 2001.
(2) Numbers in table may not sum exactly due to rounding.
19
The following table sets forth our operating results for the periods
indicated and includes the impact of the items discussed above:
Six Months Ended
June 30,
------------------
2002 2001
-------- --------
Operating Results (in millions):
Revenues................................................ $3,530.7 $3,106.7
======== ========
Gross margin:
Pipeline.............................................. $ 37.3 $ 32.6
Gathering, marketing, terminalling and storage........ 42.8 36.5
-------- --------
Total............................................. 80.1 69.1
General and administrative expense...................... (21.9) (24.0)
-------- --------
Gross profit............................................ $ 58.2 $ 45.1
======== ========
Net income.............................................. $ 31.2 $ 20.1
======== ========
Average Daily Volumes (thousands of barrels per day):
Pipeline segment:
Tariff activities
All American........................................ 64 69
Other domestic...................................... 152 157
Canada (1).......................................... 178 161
Margin activities..................................... 72 61
-------- --------
Total............................................. 466 448
======== ========
Gathering, marketing, terminalling and storage segment:
Lease gathering....................................... 405 324
Bulk purchases........................................ 67 19
-------- --------
Total............................................. 472 343
======== ========
Terminal throughput (1)................................. 76 105
======== ========
Storage leased to third parties, monthly average volumes 1,583 2,165
======== ========
- --------
(1) 2001 volume information is adjusted for consistency of comparison with 2002
presentation.
Revenues. Total revenues were $3.53 billion and $3.11 billion for the six
months ended June 30, 2002 and 2001, respectively. Excluding the impact of our
Canadian acquisitions, total revenues for the first half of 2002 would have
been $2.80 billion compared to $2.98 billion for the first half of 2001. The
decrease is primarily attributable to the decrease in the average NYMEX price
for crude oil to $23.95 per barrel for the first half of 2002 from $28.40 per
barrel for the first half of 2001. For the six months ended June 30, 2002, we
gathered from producers, using our assets or third-party assets, approximately
405,000 barrels of crude oil per day. In addition, we purchased in bulk,
primarily at major trading locations, approximately 67,000 barrels of crude oil
per day. Our revenues reflect the sale of these barrels plus the sale of
additional barrels exchanged through buy/sell arrangements entered into to
enhance the margins of the gathered and bulk-purchased crude oil.
Cost of Sales and Operations. Cost of sales and operations were $3.45
billion and $3.04 billion in the first half of 2002 and 2001, respectively, a
decrease of $0.41 million primarily due to the reasons discussed above with
respect to revenues.
General and Administrative. General and administrative expense was $21.9
million for the six months ended June 30, 2002, compared to $24.0 million for
the first half of 2001. Excluding the noncash compensation expense of $5.7
million related to the vesting of phantom units, G&A for the six months ended
June 30, 2001, would have been $18.3 million. Excluding this expense, the
resulting increase in 2002 is primarily due to $4.8 million of expenses
associated with our Canadian acquisitions, offset by a decrease in other G&A
expenses related to the domestic operations.
20
Depreciation and Amortization. Depreciation and amortization expense was
$14.1 million for the six months ended June 30, 2002, compared to $11.2 million
for the same period of 2001. Approximately $2.4 million of the increase is
attributable to our Canadian acquisitions and the remainder is due to other
assets acquired and other capital expansion projects.
Interest Expense. Interest expense decreased to $12.8 million for the six
months ended June 30, 2002, from $14.7 million for the comparative 2001 period.
The decrease is due to the capitalization of interest of $0.5 million and lower
interest rates somewhat offset by a higher average debt balance and increased
commitment fees in the first half of 2002.
Segment Results
Pipeline Operations. Gross margin from pipeline operations increased to
$37.3 million for the six months ended June 30, 2002, from $32.6 million for
the same period in 2001. The increase resulted primarily from the impact of our
Canadian acquisitions. Average daily volumes on our pipelines during the first
six months of this year were 466,000 barrels per day compared to 448,000
barrels per day last year. Approximately 10,000 barrels per day of the increase
is due to our acquisition of the Wapella pipeline in December of 2001.
Gathering, Marketing, Terminalling and Storage Activities. Gross margin from
gathering, marketing, terminalling and storage activities was approximately
$42.8 million for the six months ended June 30, 2002, compared to $36.5 million
for the same period in 2001. Excluding the impact of the noncash fair value
adjustments related to SFAS 133, gross margin for this segment would have been
$44.5 million for the six months ended June 30, 2002, compared to $36.5 million
in the prior year period. The increase was primarily related to our Canadian
acquisitions partially offset by the weaker margins from our gathering and
marketing activities as a result of the existence of a contango market.
Lease gathering volumes increased to approximately 405,000 barrels per day
in 2002 from an average of 324,000 barrels per day for the first six months of
2001, mostly due to our Canadian acquisitions. Bulk purchase volumes increased
to approximately 67,000 barrels per day in the current period from
approximately 19,000 barrels per day for the first six months of 2001. Lease
capacity decreased to an average of 1.6 million barrels per month from an
average of 2.2 million barrels per month in the prior year period and terminal
throughput averaged approximately 76,000 barrels per day and 105,000 barrels
per day in the first six months of 2002 and 2001, respectively. Both the third
party lease volumes and terminal throughput volumes are lower because we used
more of our storage capacity for contango activities during this year's period.
Liquidity and Capital Resources
Recent Events
Acquisition of Shell's West Texas Interests. In May 2002, we entered into a
definitive purchase and sale agreement to purchase certain businesses from
Shell Pipeline Company, including its interests in the Basin Pipeline System,
the Rancho Pipeline System and the Permian Basin Gathering System, for
approximately $315.0 million, excluding financing and related transaction
costs. At execution, we deposited $15.7 million into an escrow account. This
transaction was consummated on August 1, 2002, using proceeds from our
revolving credit facilities. Net of interest earned on the deposit,
approximately $9.1 million related to the settlement of pre-existing accounts
receivable and inventory balances and purchase price adjustments as provided
for in the amended purchase and sale agreement, the final amount paid to Shell
at closing totaled approximately $288.2 million cash. Including approximately
$9.6 million of estimated transaction and closing costs, the total purchase
price is approximately $322.7 million.
FERC Notice of Proposed Rulemaking. On August 1, 2002, the Federal Energy
Regulatory Commission ("FERC") issued a Notice of Proposed Rulemaking that, if
adopted, would amend its Uniform Systems of Accounts for public utilities,
natural gas companies and oil pipeline companies by requiring specific written
21
documentation concerning the management of funds from a FERC-regulated
subsidiary by a non-FERC- regulated parent. Under the proposed rule, as a
condition for participating in a cash management or money pool arrangement, the
FERC-regulated entity would be required to maintain a minimum proprietary
capital balance (stockholder's equity) of 30 percent, and the FERC regulated
entity and its parent would be required to maintain investment grade credit
ratings. If either of these conditions is not met, the FERC-regulated entity
would not be eligible to participate in the cash management or money pool
arrangement. This proposed rule is subject to a comment period of 15 days after
its publication in the Federal Register. We do not know when or if the rule
will be enacted. Although it appears that, if enacted, the rule may affect the
way in which we manage cash, we are unable to predict the full impact of this
proposed regulation on our business.
Liquidity
Cash generated from operations and our credit facilities are our primary
sources of liquidity. At June 30, 2002, we had working capital of approximately
$33.4 million, approximately $388.4 million of availability under our revolving
credit facility and $124.6 million under the letter of credit and hedged
inventory facility. Including the effect of the borrowings to fund the Shell
acquisition the amount available under our revolving credit facility at June
30, 2002, would have been approximately $100.2 million.
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. However, we are subject to business and operational risks that
could adversely effect our cash flow. A material decrease in our cash flows
would likely produce a corollary adverse effect on our borrowing capacity.
Recent Disruptions in Industry Credit Markets. As a result of business
failures, revelations of material misrepresentations and related financial
restatements by several large, well-known companies in various industries over
the last nine months, there have been significant disruptions and extreme
volatility in the financial markets and credit markets. Because of the credit
intensive nature of the energy industry and troubling disclosures by several
large, diversified energy companies, the energy industry has been especially
impacted by these developments, with the rating agencies downgrading a number
of large, energy related companies. Accordingly, in this environment we are
exposed to an increased level of direct and indirect counter-party credit and
performance risk.
The majority of our credit extensions and therefore our accounts receivable
relate to our gathering and marketing activities that can generally be
described as high volume and low margin activities, in many cases involving
complex exchanges of crude oil volumes. In transacting business with our
counter-parties, we must determine the amount, if any, of open credit lines to
extend to our counter-parties and the form and amount of financial performance
assurances we may require. The vast majority of such accounts receivable settle
monthly and any collection delays generally involve discrepancies or disputes
as to the appropriate price, volumes or quality of crude oil delivered or
exchanged and associated billing delays. Of our $358 million aggregate
receivables balance included in current assets at December 31, 2001,
approximately $331 million, or 93%, were less than 60 days past the scheduled
invoice date. Of our $499 million aggregate receivables balance included in
current assets at June 30, 2002, approximately $489 million, or 98%, were less
than 60 days past the scheduled invoice date.
We have modified our credit arrangements with certain counter-parties that
have been adversely affected by these recent events, but a large portion of the
balances more than 60 days past the invoice date, along with approximately
$10.8 million of net receivables classified as long-term, are associated with
an ongoing effort to bring substantially all balances to within sixty days of
scheduled invoice date. In certain cases, this effort involves reconciling and
resolving certain discrepancies, generally related to pricing, volumes, quality
or crude oil exchange imbalances and the majority of these receivables are
related to the period immediately following the disclosure of our unauthorized
trading losses in late 1999. Following that disclosure, a significant number of
our suppliers and trading partners temporarily reduced or eliminated our open
credit and demanded payments or
22
withheld payments due us before disputed amounts or discrepancies associated
with exchange imbalances, pricing issues and quality adjustments were
reconciled in accordance with customary industry practices. Because these
matters also arose in the midst of various software systems conversions and
acquisition integration activities, our effort to resolve outstanding claims
and discrepancies has included reprocessing and integrating historical
information on numerous software platforms. We have made significant progress
to date in this effort and intend to substantially complete this project in the
second half of 2002 and, based on the work performed to date and the scope of
the remaining work to be performed, we believe these prior period balances are
collectible and consider our reserves adequate. However, in the event our
counter-parties that experience an unanticipated deterioration in their
credit-worthiness, any addition to existing reserves or write-offs in excess of
such reserves would result in a noncash charge to earnings. We do not believe
any such charge would have a material effect on our cash flow or liquidity.
To date, these market disruptions have not had a material adverse impact on
our activities or on obtaining open credit for our own account with
counter-parties. During 2001, we received upgrades from the two rating agencies
that cover the Partnership. We are currently rated BB+ by Standard & Poor's and
on June 27, 2002, we were placed on CreditWatch with positive implications. We
are currently rated Ba2 by Moody's Investor Services with a positive outlook.
Acquisition Activity. Consistent with our acquisition strategy, we are
continuously engaged in discussions with potential sellers regarding the
possible purchase by us of midstream crude oil assets. Such acquisition efforts
involve participation by us in processes that have been made public, involve a
number of potential buyers and are commonly referred to as "auction" processes,
as well as situations in which we believe we are the only party or one of a
very limited number of potential buyers in negotiations with the potential
seller. Since 1998, we have completed 12 acquisitions for an aggregate purchase
price of $1.1 billion. We can give you no assurance that our current or future
acquisition efforts will be successful or that any such acquisition will be
completed on terms considered favorable to us.
Cash Flows
Six Months Ended
June 30,
- --------------
2002 2001
------ ------
(in millions)
Cash provided by (used in):
Operating activities.... $117.9 $(47.0)
Investing activities.... $(50.1) $(168.9)
Financing activities.... $(65.6) $213.5
Operating Activities. Net cash provided by operating activities for the six
months ended June 30, 2002, was $117.9 million primarily due to the sale of
crude oil inventory related to contango activities.
Investing Activities. Net cash used in investing activities in 2002 includes
the payment of a $15.7 million deposit related to the purchase of certain
assets from Shell Pipeline Company, $7.7 million for the Butte acquisition and
$5.1 million for the Coast/Lantern acquisition. Investing activities also
includes $20.8 million of capital expenditures related to the Cushing
expansion, the construction of the Marshall terminal in Canada and other
capital projects.
Financing Activities. Cash used in financing activities in 2002 consisted
primarily of a net repayment of $53.6 million of short-term debt related to
contango inventory transactions partially offset by net long-term borrowings of
$35.8 million used primarily to fund capital projects and acquisitions
including the deposit for the Shell acquisition. In addition, $47.0 million of
distributions were paid to unitholders and the general partner during the six
months ended June 30, 2002.
23
Universal Shelf
We have filed with the Securities and Exchange Commission a universal shelf
registration statement that, subject to effectiveness at the time of use,
allows us to issue from time to time up to an aggregate of $700 million of debt
or equity securities. In October 2001, we sold approximately $130 million of
common units under the shelf. Accordingly, as of August 6, 2002, we have the
ability to issue approximately $570 million of additional debt or equity
securities under this registration statement.
Credit Agreements
As amended, our credit facilities consist of a $350.0 million senior secured
letter of credit and hedged inventory facility (with current lender commitments
totaling $200.0 million), and a $779.0 million senior secured revolving credit
and term loan facility, each of which is secured by substantially all of our
assets. The revolving credit and term loan facility consists of a $450.0
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), a $99.0 million term loan, and a $200.0 million
term B loan. The facilities have final maturities as follows:
. as to the $350.0 million senior secured letter of credit and hedged
inventory facility, in April 2005;
. as to the aggregate $480.0 million domestic and Canadian revolver
portions, in April 2005;
. as to the $99.0 million term loan, in May 2006; and
. as to the $200.0 million term B loan, in September 2007.
In July 2002, we amended our credit facilities to enable us to consummate
the pending acquisition of certain businesses from Shell Pipeline Company and
to accommodate the increased activity level associated with the expanded asset
base, while preserving our ability to pursue additional acquisitions. The
amended facilities enable us to expand the size of the letter of credit and
hedged inventory facility from $200.0 million to $350.0 million without
additional approval from existing lenders. As amended, the financial covenants
require us to maintain:
. a current ratio (as defined) of at least 1.0 to 1.0;
. a debt coverage ratio which will not be greater than: (i) 5.0 to 1.0
through and including March 30, 2003, and 4.0 to 1.0 thereafter; and (ii)
5.25 to 1.0 on and after our issuing at least $150.0 million of unsecured
debt and, in addition, our secured debt coverage ratio will not be
greater than 4.0 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 0.7 to 1.0 through March 30,
2003, and .65 to 1.0 at any time thereafter.
For covenant compliance purposes, letters of credit and borrowings under the
letter of credit and hedged inventory facility are excluded when calculating
the debt coverage ratio.
The amended facility also permits us to issue up to $400 million of
unsecured debt having a maturity beyond the final maturity of the existing
credit facility. Upon the issuance of unsecured debt, the amount of the $450
million domestic revolving facility is reduced by an amount equal to the
following: i) 40% of the face amount of the unsecured debt issued if the face
amount is less than $350 million, less $50 million, or ii) 50% of the face
amount of the unsecured debt issued if the face amount is equal to or greater
than $350 million, less $50 million. In anticipation of a potential issuance of
senior unsecured notes during the third quarter, we entered into a sixty day
treasury lock on $100 million principal amount with a base index rate of 4.37%
and an all in basis at maturity of 4.47%.
Contingencies
We may experience future releases of crude oil into the environment from our
pipeline and storage operations, or discover past releases that were previously
unidentified. Although we maintain an inspection
24
program designed to prevent and, as applicable, to detect and address such
releases promptly, damages and liabilities incurred due to any such
environmental releases from our assets may substantially affect our business.
A pipeline, terminal or other facilities may experience damage as a result
of an accident or natural disaster. These hazards can cause personal injury and
loss of life, severe damage to and destruction of property and equipment,
pollution or environmental damage and suspension of operations. We maintain
insurance of various types that we consider adequate to cover our operations
and properties. The insurance covers all of our assets in amounts considered
reasonable. The insurance policies are subject to deductibles that we consider
reasonable and not excessive. Our insurance does not cover every potential risk
associated with operating pipelines, terminals and other facilities including
the potential loss of significant revenues. Consistent with insurance coverage
generally available to the industry, our insurance policies provide limited
coverage for losses or liabilities relating to pollution, with broader coverage
for sudden and accidental occurrences. The events of September 11 and their
overall effect on the insurance industry has had adverse impact on availability
and cost of coverage. Due to these events, insurers have excluded acts of
terrorism and sabotage from our insurance policies. On certain of our key
assets, we purchased a separate insurance policy for acts of terrorism and
sabotage.
Since the terrorist attacks, the United States Government has issued
warnings that energy assets (including our nation's pipeline infrastructure)
may be a future target of terrorist organizations. These developments expose
our operations and assets to increased risks. Any future terrorist attacks on
our facilities, those of our customers and, in some cases, those of our
competitors, could have a material adverse effect on our business.
The occurrence of a significant event not fully insured or indemnified
against, or the failure of a party to meet its indemnification obligations,
could materially and adversely affect our operations and financial condition.
We believe that we are adequately insured for public liability and property
damage to others with respect to our operations. With respect to all of our
coverage, no assurance can be given that we will be able to maintain adequate
insurance in the future at rates we consider reasonable.
Recent Accounting Pronouncements
In June 2002, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 146 "Accounting for Costs Associated with Exit or Disposal Activities".
SFAS 146 requires that a liability for a cost associated with an exit or
disposal activity be recognized when the obligation is incurred rather than at
the date of the exit plan. This Statement is effective for exit or disposal
activities that are initiated after December 31, 2002. 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.
In May 2002, the FASB issued SFAS 145 "Rescission of FASB Statements No. 4,
44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections as of
April 2002". SFAS 145 amends the treatment of gains and losses from the
extinquishment of debt only allowing those items that are truly unusual and
infrequent. The statement is effective for all transactions occurring after May
15, 2002. Effective with fiscal years beginning after May 15, 2002, any gain or
loss on extinguishment of debt that was classified as an extraordinary item in
prior periods presented that does not meet the criteria for classification as
an extraordinary item shall be reclassified. We do not believe that the
adoption of SFAS 145 will have a material effect on either our financial
position or cash flows, however, future extinguishments of debt may impact
income from continuing operations.
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.
25
Certain factors could cause actual results to differ materially from results
anticipated in the forward-looking statements. The factors include, but are not
limited to:
. abrupt or severe production declines or production interruptions in outer
continental shelf production located offshore California and transported
on the All American Pipeline;
. the availability of adequate supplies of and demand for crude oil in the
areas in which we operate;
. the effects of competition;
. the success of our risk management activities;
. the availability (or lack thereof) of acquisition or combination
opportunities;
. successful integration and future performance of acquired assets;
. continued creditworthiness and performance by our counterparties,
. our ability to receive credit on satisfactory terms;
. shortages or cost increases of power supplies, materials or labor;
. the impact of current and future laws and governmental regulations;
. environmental liabilities that are not covered by an indemnity or
insurance;
. fluctuations in the debt and equity markets; and
. general economic, market or business conditions.
Other factors described herein, such as the recent disruption in industry
credit markets discussed in Liquidity and Capital Resources and in Note 6 to
the financial statements or factors that are unknown or unpredictable, could
also have a material adverse effect on future results. Except as required by
applicable securities laws, we do not intend to update these forward-looking
statements and information.
26
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
We utilize various derivative instruments, for purposes other than trading,
to hedge our exposure to price fluctuations with respect to crude oil and
liquefied petroleum gas in storage and expected purchases, sales and
transportation of those commodities. The derivative instruments consist
primarily of futures and option contracts traded on the New York Mercantile
Exchange and over-the-counter transactions, including crude oil swap contracts
entered into with financial institutions and other counterparties. We also
utilize interest rate and foreign exchange swaps and collars to manage the
interest rate exposure on our long-term debt and foreign exchange exposure
arising from our Canadian operations. All of the interest rate and foreign
exchange instruments utilized are placed with large creditworthy financial
institutions.
In accordance with Statement of Financial Accounting Standards ("SFAS") No.
133 "Accounting for Derivative Instruments and Hedging Activities," gains and
losses on derivative instruments are deferred to Other Comprehensive Income
("OCI") and are included in revenues in the period that the related volumes are
delivered. Gains and losses on hedging instruments, which do not qualify for
hedge accounting or which represent hedge ineffectiveness and changes in the
time value component of the fair value, are included in earnings in the current
period.
The June 30, 2002, balance sheet includes a $3.8 million unrealized loss in
OCI and related assets and liabilities of $6.7 million ($5.8 million current)
and $11.5 million ($8.4 million current), respectively. Earnings for the six
months ended June 30, 2002, included a noncash loss of $1.7 million related to
the ineffective portion of our cash flow hedges, and certain derivative
contracts that did not qualify as hedges due to a low correlation between the
futures contract and hedged item (a $1.0 million noncash loss net of the
reversal of the prior period fair value adjustment related to contracts that
settled during the current period). Our hedge-related assets and liabilities
are included in other current and non-current assets and liabilities in the
consolidated balance sheet.
As of June 30, 2002, the total amount of deferred net losses on derivative
instruments recorded in OCI are expected to be reclassified to earnings during
2002, 2003 and 2004. Of the amounts deferred to OCI, a loss of $1.1 million
will be reclassified to earnings in the next twelve months.
Interest rate swaps and collars are used to hedge underlying interest
obligations. These instruments hedge interest rates on 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, 2002, we had interest rate swap and collar arrangements for an aggregate
notional principal amount of $275.0 million. These instruments are based on
LIBOR rates. The collar provides for a floor of 6.1% and a ceiling of 8.0% with
an expiration date of August 19, 2002, for a $125.0 million notional principal
amount. The fixed rate swaps provide for a rate of 3.6% for a $100.0 million
notional principal amount expiring September 2003, and a rate of 4.3% for a
$50.0 million notional principal amount expiring March 2004.
Since substantially all of our Canadian business is conducted in Canadian
dollars (CAD), we use certain financial instruments to minimize the risks of
changes in the exchange rate. These instruments include forward exchange
contracts, forward extra option contracts and cross currency swaps. At June 30,
2002, we had forward exchange contracts and forward extra option contracts that
allow us to exchange $3.0 million Canadian for at least $1.9 million U. S.
(based on a Canadian-U.S. dollar exchange rate of 1.54) quarterly during 2002
and 2003. At June 30, 2002, we also had a cross currency swap contract for an
aggregate notional principal amount of $24.8 million, effectively converting
this amount of our $99.0 million senior secured term loan (25% of the total)
from U.S. dollars to $38.3 million of Canadian dollar debt (based on a
Canadian-U.S. dollar exchange rate of 1.55). The terms of this contract mirror
the term loan, matching the amortization schedule and final maturity in May
2006. Additionally, at June 30, 2002, $13.2 million of our long-term debt was
denominated in Canadian dollars ($20.0 million CAD based on a Canadian-U.S.
dollar exchange rate of 1.52).
27
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
hedged 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.
28
PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS
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 our former general partner, its directors and certain of its officers as
defendants, and alleged 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. We reached an agreement in
principle with the plaintiffs to settle the Delaware litigation for
approximately $1.1 million. On March 6, 2002, the Delaware court approved the
settlement. The order became final in April of 2002 and the settlement amount
has been paid.
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 our former
general partner, its directors and certain of its officers as defendants. This
lawsuit contained the same claims and sought the same relief as the Delaware
derivative litigation, described above. We reached an agreement in principle
with the plaintiffs to settle the Texas litigation for approximately $112,500.
The court approved the settlement on March 18, 2002. The order became final in
April of 2002 and the settlement amount has been paid.
Other. We, in the ordinary course of business, are a claimant and/or a
defendant in various other legal proceedings. We do 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.
Items 2, 3 & 4 are not applicable and have been omitted.
Item 5. OTHER
Recent Initiatives Regarding Corporate Governance Practices.
There have been several regulatory and legislative initiatives introduced
over the past several months in response to recent events regarding accounting
issues at large public companies, resulting disruptions in the capital markets
and ensuing calls for action to prevent repetition of such events. Certain of
these initiatives include:
. On July 30, 2002, President Bush signed into law the Sarbanes--Oxley Act
of 2002 ("Act"). The Act covers a variety of areas and seeks, among other
things, to promote corporate responsibility, enhance public disclosure,
improve the quality and transparency of financial reporting and auditing,
create a Public Company Accounting Oversight Board, protect the
objectivity of research analysts and strengthen penalties for securities
law violations. Certain provisions of the Act are effective immediately,
while others require the Securities and Exchange Commission ("SEC") to
adopt relevant rules within specified periods, ranging from 30 days to
one year. One of the immediately effective provisions of the Act
requires, in connection with filing of periodic reports with the SEC that
contain financial statements, the Chief Executive Officer ("CEO") and
Chief Financial Officer ("CFO") of every publicly traded company
personally to certify that such report fully complies with the
requirements of section 13(a) or 15(d) of the Securities Exchange Act of
1934 and the information contained in such report fairly presents, in all
material respects, the financial condition and result of operations of
the company.
. The SEC has presented numerous proposed rules changes for public comment.
In addition, on June 27, 2002, the SEC issued Order No. 4-460 requiring
the filing of sworn statements by the CEO and the CFO of 945 of the
largest publicly traded companies, attesting that each respective
company's most recent periodic reports are materially truthful and
complete or explain why such a statement would not be correct. Such Order
was effective immediately and requires the certifications to be filed no
later than August 14, 2002. Plains All American Pipeline, L.P. was among
the entities included on this list.
29
. On June 6, 2002, the Corporate Accountability and Listing Standards
Committee of the New York Stock Exchange ("NYSE") submitted
recommendations to the NYSE Board of Directors designed to enhance
accountability, integrity and transparency of listed companies on the
NYSE. The committee also submitted for consideration by the NYSE Board
certain recommendations to other institutions, including the SEC and the
US Congress. On August 1, 2002, the NYSE Board adopted the final
recommendations of the committee and stated its intention to promptly
submit a rule filing with the SEC for review.
Certain of the provisions of the Act were effective as of July 30, 2002,
however, specific guidelines on how exactly to comply with certain of these
provisions have yet to be promulgated and in other cases the methods to comply
are unclear. However, Exhibits 99.1 and 99.2 to this filing include the CEO and
CFO certification required by the Act. Contemporaneously with the filing of
this document, an 8K was filed that includes the certification required by SEC
Order 4-460. Certain other issues that are not specifically mentioned in the
foregoing certifications, but which have been addressed or potentially will be
addressed in the Act or the SEC/NYSE initiatives, are discussed below:
Loans to Executives
The Act prohibits any public company from making loans to directors or
executive officers of the company. Neither the Partnership nor the general
partner has ever made any loans to directors or executive officers of the
general partner. In connection with the sale by Plains Resources Inc. of a
portion of its ownership in the general partner to members of the senior
management team in September 2001, Plains Resources Inc. loaned an aggregate of
$382,500 to five members of the senior management team. Plains Resources Inc.
is an independent entity that currently owns an approximate 29% ownership
interest in Plains All American Pipeline, L.P. Neither the partnership nor the
general partner participated in or provided any support for these loans. The
individuals receiving these loans from Plains Resources Inc. did not include
the Chief Executive Officer, Chief Operating Officer or the Chief Financial
Officer of the general partner of the partnership.
Such amounts loaned by Plains Resources Inc. represented approximately 50%
of the total purchase price from Plains Resources Inc. for these individuals'
respective interests and the balance was required to be funded with cash. Terms
of the loan provide for security in the general partner interest being
acquired, a five-year term and interest at 6% per annum, payable semi-annually.
At the date of such loans, the three-month LIBOR rate was approximately 3.5%
and the ten-year US Treasury yield was approximately 4.8%.
Auditor Independence
The Partnership's Audit Committee ("Committee") Charter complies with the
current rules of the NYSE, including provision for the Committee to consult
with management and recommend to the Board of Directors ("Board") the
appointment of the Partnership's independent auditors. The Charter also
provides for the Committee to review the activities and independence of the
independent auditors and to communicate to the independent auditors that they
are ultimately accountable to the Committee and the Board. The charter further
provides that the Committee and the Board have the ultimate authority and
responsibility to select, evaluate and, where appropriate, replace the
independent auditors. In addition, the charter provides that the Committee
actively engage in dialogue with the independent auditors with respect to any
disclosed relationships or services that may impact the objectivity and
independence of the independent auditors and recommend that the Board take
appropriate action in response to the independent auditor's report to satisfy
itself of the independent auditors' independence. As a practice, the Committee
has also consulted with management regarding the retention of the independent
auditors to perform any non-audit related services.
The proposed changes to the NYSE rules include changes to the requirements
for audit committee composition and charter. In addition the Act requires the
SEC to promulgate rules with respect to audit
30
committees. One new aspect involves prior approval by the audit committee of
any non-audit engagement of a company's independent auditors, and disclosure of
such approval. Although we engaged PricewaterhouseCoopers LLP ("PWC"), the
Partnership's independent auditors, prior to July 30, the Partnership's Audit
Committee ratified the engagement of PWC to assist the Partnership in an
assessment of the risk management activities related to its Canadian
Operations. Through June 30, 2002, the Partnership paid to its independent
auditors approximately $0.4 million and $0.4 million in audit and non-audit
fees, respectively.
Equity Compensation
Significant attention has been focused on the accounting treatment for
equity based compensation, specifically with respect to expensing compensation
cost associated with options. In connection with the formation of the
partnership in 1998 and its initial public offering in November 1998, the
general partner adopted a long-term incentive plan for employees and directors
of our general partner and its affiliates who perform services for the
partnership. The long-term incentive plan consists of two components, a
restricted unit plan and a unit option plan. As of June 30, 2002, restricted
unit grants totaling approximately 1,050,000 units were outstanding under the
restricted unit plan. No options have been granted under the unit option plan
since inception. Upon vesting of grants under the restricted unit plan, the
partnership will record a charge to earnings equal to the fair market value of
such vested units.
Separate from the partnership's long-term incentive program, certain owners
of the general partner contributed an aggregate of 450,000 subordinated units
to the general partner to provide a pool of units available for the grant of
options to management and key employees. As of June 30, 2002, approximately
367,500 options have been granted to employees and such options generally vest
in 25% increments upon achieving quarterly distribution levels on our units of
$0.525, $0.575, $0.625 and $0.675 ($2.10, $2.30, $2.50 and $2.70, annualized).
Because the exercise of the options will be satisfied out of units owned by the
general partner and will not result in dilution of units outstanding or cost to
the partnership, no expense will be recorded by the partnership upon vesting of
such options.
31
Item 6 - Exhibits and Reports on Form 8-K
A. Exhibits
10.01 Second Amended and Restated Agreement [Revolving Credit Facility] dated July 2, 2002, among
Plains Marketing, L.P., All American Pipeline, L.P., Plains All American Pipeline, L.P., and Fleet
National Bank and certain other lenders.
10.02 Second Amended and Restated Agreement [Letter of Credit and Hedged Inventory Facility] dated
July 2, 2002, among Plains Marketing, L.P., All American Pipeline, L.P., Plains All American
Pipeline, L.P., and Fleet National Bank and certain other lenders.
99.1 Certification of Chief Executive Officer of Plains All American Pipeline, L.P. pursuant to 18 U.S.C.
Section 1350.
99.2 Certification of Chief Financial Officer of Plains All American Pipeline, L.P. pursuant to 18 U.S.C.
Section 1350.
B. Reports on Form 8-K.
A current report on Form 8-K was filed on August 9, 2002, in connection with the certification by the
Chief Executive Officer and the Chief Financial Officer pursuant to SEC Order 4-460.
A current report on Form 8-K was filed on August 9, 2002, in connection with the acquisition of assets
from Shell Pipeline Company, L.P. and Equilon Enterprises LLC.
A current report on Form 8-K was furnished on July 24, 2002, in connection with Item 9 disclosure of
third-quarter estimates and earnings guidance.
A current report on Form 8-K was filed on May 24, 2002, attaching as an exhibit the Audited Balance
Sheet of Plains AAP, L.P. as of December 31, 2001.
A current report on Form 8-K was filed and furnished on May 7, 2002, in connection with Item 5 and
Item 9 disclosure of earnings and earnings guidance.
A current report on Form 8-K was furnished on May 6, 2002, in connection with Item 9 disclosure of
the execution of a purchase and sale agreement and related press release.
A current report on Form 8-K was furnished on April 19, 2002, in connection with Item 9 disclosure of
our IPAA presentation.
A current report on Form 8-K was furnished on April 5, 2002, in connection Item 9 disclosure of
acquisition negotiations.
A current report on Form 8-K was filed on March 14, 2002, attaching our Audited 2001 Financial
Statements.
A current report on Form 8-K/A was furnished on March 8, 2002, correcting the Form 8-K filed and
furnished on March 6, 2002.
A current report on Form 8-K was filed and furnished on March 6, 2002, in connection with Item 5
and Item 9 disclosure of earnings and earnings guidance.
A current report on Form 8-K was filed on March 1, 2002, attaching as an exhibit the Unaudited
Balance Sheet of Plains AAP, L.P. as of September 30, 2001.
32
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 AAP, L.P., its general
partner
By: PLAINS ALL AMERICAN GP LLC,
its general partner
Date: August 9, 2002
By: /s/ PHILLIP D. KRAMER
-----------------------------------
Phillip D. Kramer, Executive Vice
President
and Chief Financial Officer
(Principal Financial and
Accounting Officer)
Date: August 9, 2002
By: /s/ GREG L. ARMSTRONG
-----------------------------------
Greg L. Armstrong, Chairman of the
Board,
Chief Executive Officer and
Director of Plains
All American GP LLC (Principal
Executive Officer)
33