F O R M 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2002
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____
Commission file number: 1-11234
KINDER MORGAN ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
DELAWARE 76-0380342
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
500 Dallas Street, Suite 1000, Houston, Texas 77002
(Address of principal executive offices)(zip code)
Registrant's telephone number, including area code: 713-369-9000
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
The Registrant had 129,940,018 common units outstanding at November 1,
2002.
KINDER MORGAN ENERGY PARTNERS, L.P.
TABLE OF CONTENTS
Page
Number
PART I. FINANCIAL INFORMATION
Item 1: Financial Statements (Unaudited)..................................
Consolidated Statements of Income-Three and Nine Months Ended
September 30, 2002 and 2001................................... 3
Consolidated Balance Sheets-September 30, 2002 and
December 31, 2001............................................. 4
Consolidated Statements of Cash Flows-Nine Months Ended
September 30, 2002 and 2001................................... 5
Notes to Consolidated Financial Statements...................... 6
Item 2: Management's Discussion and Analysis of Financial Condition
and Results of Operations.........................................
Results of Operations........................................... 34
Financial Condition............................................. 40
Information Regarding Forward-Looking Statements................ 43
Item 3: Quantitative and Qualitative Disclosures About Market Risk........ 44
Item 4: Controls and Procedures........................................... 44
PART II. OTHER INFORMATION
Item 1: Legal Proceedings................................................. 45
Item 2: Changes in Securities and Use of Proceeds......................... 45
Item 3: Defaults Upon Senior Securities................................... 45
Item 4: Submission of Matters to a Vote of Security Holders............... 45
Item 5: Other Information................................................. 45
Item 6: Exhibits and Reports on Form 8-K.................................. 46
Signatures........................................................ 48
Certifications.................................................... 49
2
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands Except Per Unit Amounts)
(Unaudited)
Three Months Ended Sept. 30, Nine Months Ended Sept. 30,
2002 2001 2002 2001
------------ --------------- ----------- --------------
Revenues
Natural gas sales $ 740,377 $ 308,784 $1,926,180 $1,356,092
Services 357,111 263,383 926,365 752,545
Product sales and other 23,832 66,377 162,776 294,307
---------- ---------- --------- ---------
1,121,320 638,544 3,015,321 2,402,944
---------- ---------- --------- ---------
Costs and Expenses
Gas purchases and other costs of sales 729,773 319,887 1,890,342 1,447,939
Operations and maintenance 92,644 80,768 278,399 266,947
Fuel and power 24,932 21,367 64,463 52,828
Depreciation and amortization 42,546 36,701 126,495 102,724
General and administrative 27,476 24,801 87,218 76,436
Taxes, other than income taxes 14,546 10,128 40,798 34,231
---------- ---------- --------- ---------
931,917 493,652 2,487,715 1,981,105
---------- ---------- --------- ---------
Operating Income 189,403 144,892 527,606 421,839
Other Income (Expense)
Earnings from equity investments 22,818 20,899 70,386 63,249
Amortization of excess cost of equity (1,394) (2,253) (4,182) (6,759)
investments
Interest, net (46,350) (40,985) (129,236) (136,067)
Other, net 232 147 617 (256)
Minority Interest (2,410) (2,350) (7,458) (7,985)
---------- ---------- --------- ---------
Income Before Income Taxes 162,299 120,350 457,733 334,021
Income Taxes (4,119) (4,558) (13,603) (12,336)
---------- ---------- --------- ---------
Net Income $ 158,180 $ 115,792 $ 444,130 321,685
========== ========== ========== =========
General Partner's interest in Net Income $ 70,380 $ 54,824 $ 197,408 $ 147,052
Limited Partners' interest in Net Income 87,800 60,968 246,722 174,633
---------- ---------- ---------- ---------
Net Income $ 158,180 $115,792 $ 444,130 $ 321,685
========== ======== ========== =========
Basic and Diluted Limited Partners' Net $ 0.50 $ 0.37 $ 1.46 $ 1.16
========== ======== ========== =========
Income per Unit
Weighted Average Number of Units used in Computation of Limited Partners' Net Income per Unit
Basic 174,781 165,064 169,171 149,971
========== ======== ========== =========
Diluted 174,932 165,277 169,345 150,177
========== ======== ========== =========
The accompanying notes are an integral part of these
consolidated financial statements.
3
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands)
(Unaudited)
September 30, December 31,
2002 2001
---------- ----------
ASSETS
Current Assets
Cash and cash equivalents $ 62,380 $ 62,802
Accounts and notes receivable
Trade 431,848 215,860
Related parties 38,172 52,607
Inventories
Products 3,576 2,197
Materials and supplies 7,086 6,212
Gas imbalances 33,358 15,265
Gas in underground storage 11,758 18,214
Other current assets 62,691 194,886
---------- ----------
650,869 568,043
---------- ----------
Property, Plant and Equipment, net 6,098,444 5,082,612
Investments 452,774 440,518
Notes receivable 3,029 3,095
Intangibles, net 659,293 563,397
Deferred charges and other assets 241,176 75,001
---------- ----------
TOTAL ASSETS $8,105,585 $6,732,666
========== ==========
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Accounts payable
Trade $ 316,428 $ 111,853
Related parties 262 9,235
Current portion of long-term debt -- 560,219
Accrued interest 22,683 34,099
Deferred revenues 1,045 2,786
Gas imbalances 43,335 34,660
Accrued other current liabilities 209,640 209,852
---------- ----------
593,393 962,704
---------- ----------
Long-Term Liabilities and
Deferred Credits
Long-term debt, outstanding 3,611,061 2,237,015
Market value of interest rate swaps 157,545 (5,441)
Deferred revenues 29,837 29,110
Deferred income taxes 38,544 38,544
Other long-term liabilities
and deferred credits 226,452 246,464
---------- ----------
4,063,439 2,545,692
---------- ----------
Commitments and Contingencies
Minority Interest 41,927 65,236
---------- ----------
Partners' Capital
Common Units 1,848,019 1,894,677
Class B Units 127,186 125,750
i-Units 1,405,424 1,020,153
General Partner 69,293 54,628
Accumulated other comprehensive
income (loss) (43,096) 63,826
---------- ----------
3,406,826 3,159,034
---------- ----------
TOTAL LIABILITIES AND PARTNERS' CAPITAL $8,105,58 $6,732,666
========= ==========
The accompanying notes are an integral part of
these consolidated financial statements.
4
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)
Nine Months Ended Sept. 30,
---------------------------
2002 2001
---------- ----------
Cash Flows From Operating Activities
Net income $ 444,130 $ 321,685
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 126,495 102,724
Amortization of excess cost of equity investments 4,182 6,759
Earnings from equity investments (70,386) (63,249)
Distributions from equity investments 58,920 50,837
Changes in components of working capital (2,521) (59,768)
Other, net (14,551) 45,445
---------- ----------
Net Cash Provided by Operating Activities 546,269 404,433
---------- ----------
Cash Flows From Investing Activities
Acquisitions of assets (864,311) (1,453,174)
Additions to property, plant and equipment for
expansion and maintenance projects (342,562) (178,799)
Sale of property, plant and equipment,
net of removal costs 1,710 8,193
Contributions to equity investments (14,481) (2,658)
Other 1,289 (6,442)
---------- ----------
Net Cash Used in Investing Activities (1,218,355) (1,632,880)
---------- ----------
Cash Flows From Financing Activities
Issuance of debt 3,205,414 3,736,734
Payment of debt (2,432,731) (3,128,186)
Loans to related party -- (17,100)
Debt issue costs (14,180) (7,384)
Proceeds from issuance of common units 1,464 925
Proceeds from issuance of i-units 331,159 996,869
Contributions from General Partner 3,353 11,716
Distributions to partners:
Common units (227,327) (197,254)
Class B units (9,298) (5,579)
General Partner (182,742) (126,068)
Minority interest (7,365) (12,283)
Other, net 3,917 1,070
---------- ----------
Net Cash Provided by Financing Activities 671,664 1,253,460
---------- ----------
Increase (Decrease) in Cash and Cash Equivalents (422) 25,013
Cash and Cash Equivalents, beginning of period 62,802 59,319
---------- ----------
Cash and Cash Equivalents, end of period $ 62,380 $ 84,332
========== ==========
Noncash Investing and Financing Activities:
Assets acquired by the assumption of liabilities $ 153,430 $ 257,304
The accompanying notes are an integral part of
these consolidated financial statements.
5
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Organization
General
Unless the context requires otherwise, references to "we", "us", "our" or
the "Partnership" are intended to mean Kinder Morgan Energy Partners, L.P. We
have prepared the accompanying unaudited consolidated financial statements under
the rules and regulations of the Securities and Exchange Commission. Under such
rules and regulations, we have condensed or omitted certain information and
notes normally included in financial statements prepared in conformity with
accounting principles generally accepted in the United States of America. We
believe, however, that our disclosures are adequate to make the information
presented not misleading. The consolidated financial statements reflect all
adjustments that are, in the opinion of our management, necessary for a fair
presentation of our financial results for the interim periods. You should read
these consolidated financial statements in conjunction with our consolidated
financial statements and related notes included in our Annual Report on Form
10-K for the year ended December 31, 2001.
Basis of Presentation
Our consolidated financial statements include our accounts and those of our
majority-owned and controlled subsidiaries and our operating partnerships. All
significant intercompany items have been eliminated in consolidation. Certain
amounts from prior periods have been reclassified to conform to the current
presentation.
Net Income Per Unit
We compute Basic Limited Partners' Net Income per Unit by dividing our
limited partners' interest in net income by the weighted average number of units
outstanding during the period. Diluted Limited Partners' Net Income per Unit
reflects the potential dilution, by application of the treasury stock method,
that could occur if options to issue units were exercised, which would result in
the issuance of additional units that would then share in our net income.
2. Acquisitions and Joint Ventures
During the first nine months of 2002, we completed the following
acquisitions. Each of the acquisitions was accounted for under the purchase
method and the assets acquired and liabilities assumed were recorded at their
estimated fair market values as of the acquisition date. The preliminary amounts
assigned to assets and liabilities may be adjusted during a short period of time
following the acquisition. The results of operations from these acquisitions are
included in the consolidated financial statements from the effective date of
acquisition.
Cochin Pipeline
In January 2002, we purchased an additional 10% ownership interest in the
Cochin Pipeline System from NOVA Chemicals Corporation for approximately $29
million in cash. We now own approximately 44.8% of the Cochin Pipeline System.
The transaction was effective December 31, 2001, and we allocated the purchase
price to property, plant and equipment in January 2002. We record our
proportional share of joint venture revenues and expenses and cost of joint
venture assets with respect to the Cochin Pipeline System as part of our
Products Pipelines business segment.
Laser Materials Services LLC
Effective January 1, 2002, we acquired all of the equity interests of Laser
Materials Services LLC for approximately $8.9 million and the assumption of
approximately $3.3 million of liabilities, including long-term debt of $0.4
million. Laser Materials Services LLC operates 59 transload facilities in 18
states. The facilities handle dry-bulk products, including aggregates, plastics
and liquid chemicals. The acquisition of Laser Materials Services LLC expanded
our growing terminal operations and is part of our Terminals business segment.
6
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $ 8,916
Debt assumed 357
Liabilities assumed 2,967
------
Total purchase price $12,240
=======
Allocation of purchase price:
Current assets $ 879
Property, plant and equipment 11,361
-------
$12,240
=======
International Marine Terminals
Effective January 1, 2002, we acquired a 33 1/3% interest in International
Marine Terminals from Marine Terminals Incorporated. Effective February 1, 2002,
we acquired an additional 33 1/3% interest in IMT from Glenn Springs Holdings,
Inc. Our combined purchase price was approximately $40.5 million, including the
assumption of $40 million of long-term debt. IMT is a partnership that operates
a bulk terminal site in Port Sulphur, Louisiana. The Port Sulphur terminal is a
multi-purpose import and export facility, which handles approximately 7 million
tons annually of bulk products including coal, petroleum coke and iron ore. The
acquisition complements our existing bulk terminal assets. IMT is part of our
Terminals business segment.
Our purchase price and our allocation to assets acquired, liabilities
assumed and minority interest was as follows (in thousands):
Purchase price:
Cash received, net of transaction costs $(3,781)
Debt assumed 40,000
Liabilities assumed 4,249
-------
Total purchase price: $40,468
=======
Allocation of purchase price:
Current assets $ 6,600
Property, plant and equipment 31,781
Deferred charges and other assets 139
Minority interest 1,948
-------
$40,468
=======
Kinder Morgan Tejas
Effective January 31, 2002, we acquired all of the equity interests of
Tejas Gas, LLC, a wholly-owned subsidiary of InterGen (North America), Inc., for
approximately $832.6 million, including the assumption of approximately $103.8
million of liabilities. Tejas Gas, LLC consists primarily of a 3,400-mile
natural gas intrastate pipeline system that extends from south Texas along the
Mexico border and the Texas Gulf Coast to near the Louisiana border and north
from near Houston to east Texas. The acquisition expands our natural gas
operations within the State of Texas. The acquired assets are referred to as
Kinder Morgan Tejas in this report and are included in our Natural Gas Pipelines
business segment.
The allocation of our purchase price to the assets and liabilities of
Kinder Morgan Tejas is preliminary, pending final purchase price adjustments. It
was based on an independent appraisal of fair market values as follows (in
thousands):
Purchase price:
Cash paid, including transaction costs $ 728,768
Liabilities assumed 103,787
---------
Total purchase price $ 832,555
=========
Allocation of purchase price:
Current assets $ 72,610
Property, plant and equipmemt,
incl. cushion gas 689,052
Goodwill 70,893
---------
$ 832,555
=========
The $70.9 million of goodwill was assigned to our Natural Gas Pipelines
business segment and the entire amount is expected to be deductible for tax
purposes.
7
Milwaukee Bagging Operations
Effective May 1, 2002, we purchased a bagging operation facility adjacent
to our Milwaukee, Wisconsin dry-bulk terminal for $8.5 million. The purchase
enhances the operations at our Milwaukee terminal, which is capable of handling
up to 150,000 tons per year of fertilizer and salt for de-icing and livestock
purposes. The Milwaukee bagging operations are included in our Terminals
business segment.
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $8,500
------
Total purchase price $8,500
======
Allocation of purchase price:
Current assets $ 40
Property, plant and equipment 3,140
Goodwill 5,320
------
$8,500
======
The $5.3 million of goodwill was assigned to our Terminals business segment
and the entire amount is expected to be deductible for tax purposes.
Trailblazer Pipeline Company
On May 6, 2002, we acquired the remaining 33 1/3% ownership interest in
Trailblazer Pipeline Company from Enron Trailblazer Pipeline Company for $68
million in cash. We now own 100% of Trailblazer Pipeline Company. During the
first quarter of 2002, we paid $12.0 million to CIG Trailblazer Gas Company, an
affiliate of El Paso Corporation, in exchange for CIG's relinquishment of its
rights to become a 7% to 8% equity owner in Trailblazer Pipeline Company in
mid-2002.
Our purchase price and our allocation to assets acquired, liabilities
assumed and minority interest was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $80,125
-------
Total purchase price $80,125
=======
Allocation of purchase price:
Property, plant and equipmemt $41,409
Goodwill 15,000
Minority interest 23,716
-------
$80,125
=======
The $15.0 million of goodwill was assigned to our Natural Gas Pipelines
business segment and the entire amount is expected to be deductible for tax
purposes.
Owensboro Gateway Terminal
Effective September 1, 2002, we acquired the Lanham River Terminal near
Owensboro, Kentucky and related equipment for $7.7 million. As of September 30,
2002, we have paid approximately $7.2 million and established a $0.5 million
liability for final purchase price settlements. The facility is one of the
nation's largest storage and handling points for bulk aluminum. The terminal
also handles a variety of other bulk products, including petroleum coke, lime
and de-icing salt. The terminal is situated on a 92-acre site along the Ohio
River, and the purchase expands our presence along the river, complementing our
existing facilities located near Cincinnati, Ohio and Moundsville, West
Virginia. The acquired terminal will be referred to as the Owensboro Gateway
Terminal and is included in our Terminals business segment.
8
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $7,140
Purchase price reserve 500
Liabilities assumed 11
------
Total purchase price $7,651
======
Allocation of purchase price:
Current assets $ 42
Property, plant and equipment 4,265
Intangibles-agreements 54
Goodwill 3,290
------
$7,651
======
The $3.3 million of goodwill was assigned to our Terminals business segment
and the entire amount is expected to be deductible for tax purposes.
Pro Forma Information
The following summarized unaudited Pro Forma Consolidated Income Statement
information for the nine months ended September 30, 2002 and 2001, assumes all
of the acquisitions we have made since January 1, 2001, including the ones
listed above, had occurred as of January 1, 2001. We have prepared these
unaudited Pro Forma financial results for comparative purposes only. These
unaudited Pro Forma financial results may not be indicative of the results that
would have occurred if we had completed these acquisitions as of January 1, 2001
or the results that will be attained in the future. Amounts presented below are
in thousands, except for the per unit amounts:
Pro Forma
Nine Months Ended
September 30,
2002 2001
---- ----
(Unaudited)
Revenues $3,257,969 $4,743,371
Operating Income 532,872 472,546
Net Income 452,641 389,660
Basic and diluted Limited Partners' Net Income
per unit $ 1.45 $ 1.05
Subsequent Event
On October 10, 2002, we announced that we had completed the acquisition of
the former ICOM marine terminal in St. Gabriel, Louisiana from the Canadian
National Railroad for approximately $17.6 million. The acquisition was made
effective September 1, 2002. The facility features 400,000 barrels of liquids
storage capacity and a related pipeline network that serves one of the fastest
growing petrochemical production areas in the country. The acquisition further
expands our terminal businesses along the Mississippi River. The acquired
terminal will be referred to as the Kinder Morgan St. Gabriel terminal and will
be included in our Terminals business segment.
3. Litigation and Other Contingencies
Federal Energy Regulatory Commission Proceedings
SFPP, L.P.
SFPP, L.P. is the subsidiary limited partnership that owns our Pacific
operations, excluding CALNEV pipeline and related terminals acquired
from GATX Corporation. Tariffs charged by SFPP are subject to certain
proceedings at the Federal Energy Regulatory Commission involving shippers'
complaints regarding the interstate rates, as well as practices and the
jurisdictional nature of certain facilities and services, on our Pacific
operations' pipeline systems. Generally, the interstate rates on our Pacific
operations' pipeline systems are "grandfathered" under the Energy Policy Act
of 1992 unless "substantially changed circumstances" are found to exist. To
the extent "substantially changed circumstances" are found to exist, our Pacific
operations may be subject to substantial exposure under these FERC complaints.
We currently believe that these FERC complaints seek approximately $197 million
in tariff reparations and prospective annual tariff reductions, the aggregate
average annual impact of which would be approximately $45 million. However,
even if "substantially changed circumstances" are found to exist, we believe
that the resolution of these FERC complaints will be for amounts substantially
less than the amount sought.
OR92-8, et al. proceedings. In September 1992, El Paso Refinery, L.P. filed
a protest/complaint with the FERC:
o challenging SFPP's East Line rates from El Paso, Texas to Tucson and
Phoenix, Arizona;
9
o challenging SFPP's proration policy; and
o seeking to block the reversal of the direction of flow of SFPP's
six-inch pipeline between Phoenix and Tucson.
At various subsequent dates, the following other shippers on SFPP's South
System filed separate complaints, and/or motions to intervene in the FERC
proceeding, challenging SFPP's rates on its East and/or West Lines:
o Chevron U.S.A. Products Company;
o Navajo Refining Company;
o ARCO Products Company;
o Texaco Refining and Marketing Inc.;
o Refinery Holding Company, L.P. (a partnership formed by El Paso
Refinery's long-term secured creditors that purchased its refinery in
May 1993);
o Mobil Oil Corporation; and
o Tosco Corporation.
Certain of these parties also claimed that a gathering enhancement fee at SFPP's
Watson Station in Carson, California was charged in violation of the Interstate
Commerce Act.
The FERC consolidated these challenges in Docket Nos. OR92-8-000, et al.,
and ruled that they are complaint proceedings, with the burden of proof on the
complaining parties. These parties must show that SFPP's rates and practices at
issue violate the requirements of the Interstate Commerce Act.
A FERC administrative law judge held hearings in 1996, and issued an
initial decision on September 25, 1997. The initial decision agreed with SFPP's
position that "changed circumstances" had not been shown to exist on the West
Line, and therefore held that all West Line rates that were "grandfathered"
under the Energy Policy Act of 1992 were deemed to be just and reasonable and
were not subject to challenge, either for the past or prospectively, in the
Docket No. OR92-8 et al. proceedings. SFPP's Tariff No. 18 for movement of jet
fuel from Los Angeles to Tucson, which was initiated subsequent to the enactment
of the Energy Policy Act, was specifically excepted from that ruling.
The initial decision also included rulings generally adverse to SFPP on
such cost of service issues as:
o the capital structure to be used in computing SFPP's 1985 starting
rate base;
o the level of income tax allowance; and
o the recovery of civil and regulatory litigation expenses and certain
pipeline reconditioning costs.
The administrative law judge also ruled that SFPP's gathering enhancement
service at Watson Station was subject to FERC jurisdiction and ordered SFPP to
file a tariff for that service, with supporting cost of service documentation.
SFPP and other parties asked the Commission to modify various rulings made
in the initial decision. On January 13, 1999, the FERC issued its Opinion No.
435, which affirmed certain of those rulings and reversed or modified others.
With respect to SFPP's West Line, the FERC affirmed that all but one of the
West Line rates are "grandfathered" as just and reasonable and that "changed
circumstances" had not been shown to satisfy the complainants' threshold burden
necessary to challenge those rates. The FERC further held that the rate stated
in Tariff No. 18 did not require rate reduction. Accordingly, the FERC dismissed
all complaints against the West Line rates without any requirement that SFPP
reduce, or pay any reparations for, any West Line rate.
With respect to the East Line rates, Opinion No. 435 made several changes
in the initial decision's methodology for calculating the rate base. It held
that the June 1985 capital structure of SFPP's parent company at that time,
rather than SFPP's 1988 partnership capital structure, should be used to
calculate the starting rate base and modified the accumulated deferred income
tax and allowable cost of equity used to calculate the rate base. It also ruled
that SFPP would not owe reparations to any complainant for any period prior to
the date on which that complainant's complaint was filed, thus reducing by two
years the potential reparations period claimed by most complainants.
SFPP and certain complainants sought rehearing of Opinion No. 435 by the
FERC. In addition, ARCO, RHC, Navajo, Chevron and SFPP filed petitions for
review of Opinion No. 435 with the U.S. Court of Appeals for the District of
Columbia Circuit, all of which were either dismissed as premature or held in
abeyance pending FERC
10
action on the rehearing requests.
On March 15, 1999, as required by the FERC's order, SFPP submitted a
compliance filing implementing the rulings made in Opinion No. 435, establishing
the level of rates to be charged by SFPP in the future, and setting forth the
amount of reparations that would be owed by SFPP to the complainants under the
order. The complainants contested SFPP's compliance filing.
On May 17, 2000, the FERC issued its Opinion No. 435-A, which modified
Opinion No. 435 in certain respects. It denied requests to reverse its rulings
that SFPP's West Line rates and Watson Station gathering enhancement facilities
fee are entitled to be treated as "grandfathered" rates under the Energy Policy
Act. It suggested, however, that if SFPP had fully recovered the capital costs
of the gathering enhancement facilities, that might form the basis of an amended
"changed circumstances" complaint.
Opinion No. 435-A granted a request by Chevron and Navajo to require that
SFPP's December 1988 partnership capital structure be used to compute the
starting rate base from December 1983 forward, as well as a request by SFPP to
vacate a ruling that would have required the elimination of approximately $125
million from the rate base used to determine capital structure. It also granted
two clarifications sought by Navajo, to the effect that SFPP's return on its
starting rate base should be based on SFPP's capital structure in each given
year (rather than a single capital structure from the outset) and that the
return on deferred equity should also vary with the capital structure for each
year. Opinion No. 435-A denied the request of Chevron and Navajo that no income
tax allowance be recognized for the limited partnership interests held by SFPP's
corporate parent, as well as SFPP's request that the tax allowance should
include interests owned by certain non-corporate entities. However, it granted
Navajo's request to make the computation of interest expense for tax allowance
purposes the same as for debt return.
Opinion No. 435-A reaffirmed that SFPP may recover certain litigation costs
incurred in defense of its rates (amortized over five years), but reversed a
ruling that those expenses may include the costs of certain civil litigation
with Navajo and El Paso. It also reversed a prior decision that litigation costs
should be allocated between the East and West Lines based on throughput, and
instead adopted SFPP's position that such expenses should be split equally
between the two systems.
As to reparations, Opinion No. 435-A held that no reparations would be
awarded to West Line shippers and that only Navajo was eligible to recover
reparations on the East Line. It reaffirmed that a 1989 settlement with SFPP
barred Navajo from obtaining reparations prior to November 23, 1993, but allowed
Navajo reparations for a one-month period prior to the filing of its December
23, 1993 complaint. Opinion No. 435-A also confirmed that FERC's indexing
methodology should be used in determining rates for reparations purposes and
made certain clarifications sought by Navajo.
Opinion No. 435-A denied Chevron's request for modification of SFPP's
prorationing policy. That policy required customers to demonstrate a need for
additional capacity if a shortage of available pipeline space existed. SFPP's
prorationing policy has since been changed to eliminate the "demonstrated need"
test.
Finally, Opinion No. 435-A directed SFPP to revise its initial compliance
filings to reflect the modified rulings. It eliminated the refund obligation for
the compliance tariff containing the Watson Station gathering enhancement fee,
but required SFPP to pay refunds to the extent that the initial compliance
tariff East Line rates exceeded the rates produced under Opinion No. 435-A.
In June 2000, several parties filed requests for rehearing of rulings made
in Opinion No. 435-A. Chevron and RHC both sought reconsideration of the FERC's
ruling that only Navajo is entitled to reparations for East Line shipments. SFPP
sought rehearing of the FERC's:
o decision to require use of the December 1988 partnership capital
structure for the period 1984-88 in computing the starting rate base;
o elimination of civil litigation costs;
o refusal to allow any recovery of civil litigation settlement payments;
and
o failure to provide any allowance for regulatory expenses in
prospective rates.
On July 17, 2000, SFPP submitted a compliance filing implementing the
rulings made in Opinion No. 435-A, together with a calculation of reparations
due to Navajo and refunds due to other East Line shippers. SFPP also filed a
tariff stating revised East Line rates based on those rulings.
11
ARCO, Chevron, Navajo, RHC, Texaco and SFPP sought judicial review of
Opinion No. 435-A in the U.S. Court of Appeals for the District of Columbia
Circuit. All of those petitions except Chevron's were either dismissed as
premature or held in abeyance pending action on the rehearing requests. On
September 19, 2000, the court dismissed Chevron's petition for lack of
prosecution, and subsequently denied a motion by Chevron for reconsideration of
that dismissal.
On September 13, 2001, the FERC issued Opinion No. 435-B, which ruled on
requests for rehearing and comments on SFPP's compliance filing. Based on those
rulings, the FERC directed SFPP to submit a further revised compliance filing,
including revised tariffs and revised estimates of reparations and refunds.
Opinion No. 435-B denied SFPP's requests for rehearing, which involved the
capital structure to be used in computing starting rate base, SFPP's ability to
recover litigation and settlement costs incurred in connection with the Navajo
and El Paso civil litigation, and the provision for regulatory costs in
prospective rates. However, it modified the Commission's prior rulings on
several other issues. It reversed the ruling that only Navajo is eligible to
seek reparations, holding that Chevron, RHC, Tosco and Mobil are also eligible
to recover reparations for East Line shipments. It ruled, however, that Ultramar
is not eligible for reparations in the Docket No. OR92-8 et al. proceedings .
The FERC also changed prior rulings that had permitted SFPP to use certain
litigation, environmental and pipeline rehabilitation costs that were not
recovered through the prescribed rates to offset overearnings (and potential
reparations) and to recover any such costs that remained by means of a surcharge
to shippers. Opinion No. 435-B required SFPP to pay reparations to each
complainant without any offset for unrecovered costs. It required SFPP to
subtract from the total 1995-1998 supplemental costs allowed under Opinion No.
435-A any overearnings not paid out as reparations, and allowed SFPP to recover
any remaining costs from shippers by means of a five-year surcharge beginning
August 1, 2000. Opinion No. 435-B also ruled that SFPP would only be permitted
to recover certain regulatory litigation costs through the surcharge, and that
the surcharge could not include environmental or pipeline rehabilitation costs.
Opinion No. 435-B directed SFPP to make additional changes in its revised
compliance filing, including:
o using a remaining useful life of 16.8 years in amortizing its starting
rate base, instead of 20.6 years;
o removing the starting rate base component from base rates as of August
1, 2001;
o amortizing the accumulated deferred income tax balance beginning in
1992, rather than 1988;
o listing the corporate unitholders that were the basis for the income
tax allowance in its compliance filing and certifying that those
companies are not Subchapter S corporations; and
o "clearly" excluding civil litigation costs and explaining how it
limited litigation costs to FERC-related expenses and assigned them to
appropriate periods in making reparations calculations.
On October 15, 2001, Chevron and RHC filed petitions for rehearing of
Opinion No. 435-B. Chevron asked the FERC to clarify:
o the period for which Chevron is entitled to reparations; and
o whether East Line shippers that have received the benefit of
Commission-prescribed rates for 1994 and subsequent years must show
that there has been a substantial divergence between the cost of
service and the change in the Commission's rate index in order to have
standing to challenge SFPP rates for those years in pending or
subsequent proceedings.
RHC's petition contended that Opinion No. 435-B should be modified on
rehearing, to the extent it:
o suggested that a "substantial divergence" standard applies to
complaint proceedings challenging the total level of SFPP's East Line
rates subsequent to the Docket No. OR92-8 et al. proceedings;
o required a substantial divergence to be shown between SFPP's cost of
service and the change in the FERC oil pipeline index in such
subsequent complaint proceedings, rather than a substantial divergence
between the cost of service and SFPP's revenues; and
o permitted SFPP to recover 1993 rate case litigation expenses through a
surcharge mechanism.
ARCO, Ultramar and SFPP filed petitions for review of Opinion No. 435-B
(and in SFPP's case, Opinion Nos. 435 and 435-A) in the U.S. Court of Appeals
for the District of Columbia Circuit. The court consolidated the Ultramar and
SFPP petitions with the consolidated cases held in abeyance and ordered that the
consolidated cases be returned to its active docket.
12
On November 7, 2001, the FERC issued an order ruling on the petitions for
rehearing of Opinion No. 435-B. The FERC held that Chevron's eligibility for
reparations should be measured from August 3, 1993, rather than the September
23, 1992 date sought by Chevron. The FERC also clarified its prior ruling with
respect to the "substantial divergence" test, holding that in order to be
considered on the merits, complaints challenging the SFPP rates set by applying
the FERC's indexing regulations to the 1994 cost of service derived under the
Opinion No. 435 orders must demonstrate a substantial divergence between the
indexed rates and the pipeline's actual cost of service. Finally, the FERC held
that SFPP's 1993 regulatory costs should not be included in the surcharge for
the recovery of supplemental costs.
On November 20, 2001, SFPP submitted its compliance filing and tariffs
implementing Opinion No. 435-B and the FERC's November 7, 2001 order. Motions to
intervene and protest were subsequently filed by ARCO, Mobil (which now submits
filings under the name ExxonMobil), RHC, Navajo and Chevron, alleging that SFPP:
o should have calculated the supplemental cost surcharge differently;
o did not provide adequate information on the taxpaying status of its
unitholders; and
o failed to estimate potential reparations for ARCO.
On December 7, 2001, Chevron filed a petition for rehearing of the FERC's
November 7, 2001 order. The petition requested the Commission to specify whether
Chevron would be entitled to reparations for the two year period prior to the
August 3, 1993 filing of its complaint.
On December 10, 2001, SFPP filed a response to those claims. On December
14, 2001, SFPP filed a revised compliance filing and new tariff correcting an
error that had resulted in understating the proper surcharge and tariff rates.
On December 20, 2001, the FERC's Director of the Division of Tariffs and
Rates Central issued two letter orders rejecting SFPP's November 20, 2001 and
December 14, 2001 tariff filings because they were not made effective
retroactive to August 1, 2000. On January 11, 2002, SFPP filed a request for
rehearing of those orders by the Commission, on the ground that the FERC has no
authority to require retroactive reductions of rates filed pursuant to its
orders in complaint proceedings.
On January 7, 2002, SFPP and RHC filed petitions for review of the FERC's
November 7, 2001 order in the U.S. Court of Appeals for the District of Columbia
Circuit. On January 8, 2002, the court consolidated those petitions with the
petitions for review of Opinion Nos. 435, 435-A and 435-B. On January 24, 2002,
the court ordered the consolidated proceedings to be held in abeyance until the
FERC acts on Chevron's request for rehearing of the November 7, 2001 order.
Motions to intervene and protest the December 14, 2001 corrected
submissions were filed by Navajo, ARCO and ExxonMobil. Ultramar requested leave
to file an out-of-time intervention and protest of both the November 20, 2001
and December 14, 2001 submissions. On January 14, 2002, SFPP responded to those
filings to the extent they were not mooted by the orders rejecting the tariffs
in question.
On February 15, 2002, the Commission denied rehearing of the Director of
the Division of Tariffs and Rates Central's letter orders. On February 21, 2002,
SFPP filed a motion requesting that the FERC clarify whether it intended SFPP to
file a retroactive tariff or simply make a compliance filing calculating the
effects of Opinion No. 435-B back to August 1, 2000; in the event the order was
clarified to require a retroactive tariff filing, SFPP asked the FERC to stay
that requirement pending judicial review.
On April 8, 2002, SFPP filed a petition for review of the FERC's February
15, 2002 Order in the U.S. Court of Appeals for the District of Columbia
Circuit. BP West Coast Products, LLC (formerly ARCO); ExxonMobil; Tosco
Corporation; and Ultramar, Inc. and Valero Energy Corporation filed motions to
intervene in that proceeding. On April 9, 2002, the Court of Appeals
consolidated SFPP's petition with the petitions for review of the FERC's prior
orders and directed the parties "to file motions to govern future proceedings"
by May 9, 2002. Motions were filed by SFPP, RHC, Navajo, Chevron and the
"Indicated Parties" (BP West Coast Products, ExxonMobil, Ultramar and Tosco).
The FERC requested that the Court continue to hold the consolidated cases in
abeyance pending the completion of proceedings before the agency on rehearing.
On June 25, 2002, the Court granted the ExxonMobil and Valero Energy
motions to intervene, and directed intervenors on the side of petitioners to
notify the court of that status and provide a statement of issues to be raised.
ExxonMobil filed a notice on July 2, 2002; Ultramar, Inc. and Valero Energy on
July 10, 2002. On July 12, 2002, SFPP responded to the ExxonMobil notice in
order to urge the Court not to rely on ExxonMobil's categorization of
13
the issues and party alignments in allocating briefing.
On May 31, 2002, SFPP filed FERC Tariff No. 70, which implemented the
FERC's annual indexing adjustment. Motions to intervene and protest were filed
by Navajo and Chevron, contesting any indexing adjustment to the litigation
surcharge permitted by Opinion No. 435-B. On June 28, 2002, the FERC's Director
of the Division of Tariffs and Rates rejected Tariff No. 70 on the ground that
the surcharge should not be indexed. On July 2, 2002, SFPP filed FERC Tariff No.
73 to replace Tariff No. 70 in compliance with that decision, which resulted in
an average reduction from Tariff No. 70 of approximately $.0002 per barrel.
On September 26, 2002, the FERC issued an order ruling on the protests
against SFPP's November 20, 2001 and December 14, 2001 compliance filings
implementing Opinion No. 435-B and the November 7, 2001 Order. The FERC held
that:
o SFPP must measure supplemental costs against the total amount of
reparations for the entire reparations period (as opposed to
year-by-year);
o SFPP will not be permitted to include in its supplemental costs (a)
litigation expenses incurred during 1999 and 2000 or (b) payments made
to Navajo and RHC to settle certain FERC litigation;
o the tariff surcharge collected by SFPP for all shipments between
August 1, 2000 and December 1, 2001 is subject to refund; and
o in calculating its tax allowance, SFPP must exclude the ownership
interest attributable to an entity that the FERC found to be a mutual
fund.
The FERC rejected the requests by Navajo, ARCO (now BP West Coast Products)
and Mobil (now ExxonMobil) to extend the period for which they are entitled to
reparations beyond the periods specified in prior orders.
The September 26, 2002 Order also ruled on SFPP's request for clarification
of the February 15, 2002 Order as to whether it was required to make a
retroactive tariff filing or rather a compliance filing calculating the effects
of Opinion No. 435-B beginning August 1, 2000. The FERC held that SFPP was
required to file a tariff retroactive to August 1, 2000. The FERC did not rule
on SFPP's alternative request for a stay. The FERC also ruled on Chevron's
request for rehearing of the November 7, 2001 Order, clarifying that Chevron was
eligible for reparations for shipments on the East Line for the two years prior
to the filing of its complaint.
On October 22, 2002, ExxonMobil filed a Request for Clarification or, in
the Alternative, Rehearing of the September 26, 2002 Order. ExxonMobil requested
that the FERC clarify that ExxonMobil was eligible for reparations for East Line
rates.
On October 28, 2002, SFPP submitted its compliance and tariff filing
implementing the September 26, 2002 Order.
Following the September 26, 2002 Order, several parties filed motions to
govern future proceedings with the U.S. Court of Appeals for the District of
Columbia Circuit. BP West Coast Products LLC and ExxonMobil (the "Indicated
Parties") and Valero Energy Corporation, Ultramar Inc. and Tosco Corporation
(the "Joint Parties") requested that the court return the petitions for review
to its active docket but sever the docket involving compliance filing issues.
The FERC filed a motion that did not take a definitive position on whether the
petitions for review should continue to be held in abeyance, but noted that
compliance filing issues were still pending before the FERC. SFPP, Chevron,
Navajo and RHC filed responses to the motions to govern future proceedings.
On October 18, 2002, Chevron filed a petition for review of Opinion Nos.
435, 435-A and 435-B in the U.S. Court of Appeals for the District of Columbia
Circuit. Petitions for review of the September 26, 2002 Order have been filed in
the U.S. Court of Appeals for the District of Columbia Circuit by Navajo, on
October 24, 2002, and by SFPP, on November 8, 2002.
Sepulveda proceedings. In December 1995, Texaco filed a complaint at FERC
(Docket No. OR96-2) alleging that movements on SFPP's Sepulveda pipelines (Line
Sections 109 and 110) to Watson Station, in the Los Angeles basin, were subject
to FERC's jurisdiction under the Interstate Commerce Act, and, if so, claimed
that the rate for that service was unlawful. Texaco sought to have its claims
addressed in the OR92-8 proceeding discussed above. Several other West Line
shippers filed similar complaints and/or motions to intervene. The FERC
consolidated all of these filings into Docket Nos. OR96-2 and set the claims for
a separate hearing. A hearing before an administrative law judge was held in
December 1996.
14
In March 1997, the judge issued an initial decision holding that the
movements on the Sepulveda pipelines were not subject to FERC jurisdiction. On
August 5, 1997, the FERC reversed that decision. On October 6, 1997, SFPP filed
a tariff establishing the initial interstate rate for movements on the Sepulveda
pipelines at the preexisting rate of five cents per barrel. Several shippers
protested that rate. In December 1997, SFPP filed an application for authority
to charge a market-based rate for the Sepulveda service, which application was
protested by several parties. On September 30, 1998, the FERC issued an order
finding that SFPP lacks market power in the Watson Station destination market
and that, while SFPP appeared to lack market power in the Sepulveda origin
market, a hearing was necessary to permit the protesting parties to substantiate
allegations that SFPP possesses market power in the origin market. A hearing
before a FERC administrative law judge on this limited issue was held in
February 2000.
On December 21, 2000, the FERC administrative law judge issued his initial
decision finding that SFPP possesses market power over the Sepulveda origin
market. The ultimate disposition of SFPP's application is pending before the
FERC.
Following the issuance of the initial decision in the Sepulveda case, the
FERC judge indicated an intention to proceed to consideration of the justness
and reasonableness of the existing rate for service on the Sepulveda pipelines.
On February 22, 2001, the FERC granted SFPP's motion to block such consideration
and to defer consideration of the pending complaints against the Sepulveda rate
until after FERC's final disposition of SFPP's market rate application.
OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar filed a
complaint at FERC (Docket No. OR97-2) challenging SFPP's West Line rates,
claiming they were unjust and unreasonable and no longer subject to
grandfathering. In October 1997, ARCO, Mobil and Texaco filed a complaint at the
FERC (Docket No. OR98-1) challenging the justness and reasonableness of all of
SFPP's interstate rates, raising claims against SFPP's East and West Line rates
similar to those that have been at issue in Docket Nos. OR92-8, et al., but
expanding them to include challenges to SFPP's grandfathered interstate rates
from the San Francisco Bay area to Reno, Nevada and from Portland to Eugene,
Oregon - the North Line and Oregon Line. In November 1997, Ultramar Diamond
Shamrock Corporation filed a similar, expanded complaint (Docket No. OR98-2).
Tosco Corporation filed a similar complaint in April 1998. The shippers seek
both reparations and prospective rate reductions for movements on all of the
lines. SFPP answered each of these complaints. FERC issued orders accepting the
complaints and consolidating them into one proceeding (Docket No. OR96-2, et
al.), but holding them in abeyance pending a FERC decision on review of the
initial decision in Docket Nos. OR92-8, et al.
In a companion order to Opinion No. 435, the FERC gave the complainants an
opportunity to amend their complaints in light of Opinion No. 435, which the
complainants did in January 2000. On May 17, 2000, the FERC issued an order
finding that the various complaining parties had alleged sufficient grounds for
their complaints to go forward to a hearing to assess whether any of the
challenged rates that are grandfathered under the Energy Policy Act will
continue to have such status and, if the grandfathered status of any rate is not
upheld, whether the existing rate is just and reasonable.
In August 2000, Navajo and RHC filed complaints against SFPP's East Line
rates and Ultramar filed an additional complaint updating its pre-existing
challenges to SFPP's interstate pipeline rates. In September 2000, FERC accepted
these new complaints and consolidated them with the ongoing proceeding in Docket
No. OR96-2, et al.
A hearing in this consolidated proceeding was held from October 2001 to
March 2002. An initial decision by the administrative law judge is expected in
the fourth quarter of 2002.
The complainants have alleged a variety of grounds for finding
"substantially changed circumstances." Applicable rules and regulations in this
field are vague, relevant factual issues are complex, and there is little
precedent available regarding the factors to be considered or the method of
analysis to be employed in making a determination of "substantially changed
circumstances," which is the showing necessary to render "grandfathered" rates
subject to challenge. Given the newness of the grandfathering standard under the
Energy Policy Act and limited precedent, we cannot predict how these allegations
will be viewed by the FERC.
If "substantially changed circumstances" are found, SFPP rates previously
"grandfathered" under the Energy Policy Act will lose their "grandfathered"
status. If these rates are found to be unjust and unreasonable, shippers may be
entitled to a prospective rate reduction and a complainant may be entitled to
reparations for periods from the date of its complaint to the date of the
implementation of the new rates.
15
OR02-4 proceedings. On February 11, 2002, Chevron, an intervenor in the
OR96-2 proceeding, filed a complaint against SFPP in Docket No. OR02-4 along
with a motion to consolidate the complaint with the OR96-2 proceeding. On May
21, 2002, the FERC dismissed Chevron's complaint and motion to consolidate.
Chevron filed a request for rehearing and on September 25, 2002, the FERC
dismissed Chevron's rehearing request. Chevron continues to participate in the
OR96-2 proceeding as an intervenor.
We are not able to predict with certainty the final outcome of the pending
FERC proceedings involving SFPP, should they be carried through to their
conclusion, or whether we can reach a settlement with some or all of the
complainants. Although it is possible that current or future proceedings could
be resolved in a manner adverse to us, we believe that the resolution of such
matters will not have a material adverse effect on our business, financial
position or results of operations.
CALNEV Pipe Line LLC
We acquired CALNEV Pipe Line LLC in March 2001. CALNEV provides interstate
and intrastate transportation from an interconnection with SFPP at Colton,
California to destinations in and around Las Vegas, Nevada.
In April 2002, Chevron filed a complaint against CALNEV's interstate rates,
making allegations of unjust and unreasonable rates. CALNEV answered Chevron's
complaint on May 16, 2002, and Chevron moved for leave to respond to CALNEV's
answer on June 17, 2002.
In September of 2002, CALNEV and Chevron were able to reach a mutually
agreeable resolution of the disputed claims, and a settlement was executed. In
the settlement agreement, the parties agreed, among other things, that for a
period of five years, CALNEV would not seek a rate increase at the FERC or the
California Public Utilities Commission except as permitted under four specific
exceptions and that Chevron would not file complaints against CALNEV's rates,
provided it complies with such exceptions. On October 10, 2002, the FERC granted
the parties' joint motion to dismiss the complaint with prejudice.
California Public Utilities Commission Proceeding
ARCO, Mobil and Texaco filed a complaint against SFPP with the California
Public Utilities Commission on April 7, 1997. The complaint challenges rates
charged by SFPP for intrastate transportation of refined petroleum products
through its pipeline system in the State of California and requests prospective
rate adjustments. On October 1, 1997, the complainants filed testimony seeking
prospective rate reductions aggregating approximately $15 million per year.
On August 6, 1998, the CPUC issued its decision dismissing the
complainants' challenge to SFPP's intrastate rates. On June 24, 1999, the CPUC
granted limited rehearing of its August 1998 decision for the purpose of
addressing the proper ratemaking treatment for partnership tax expenses, the
calculation of environmental costs and the public utility status of SFPP's
Sepulveda Line and its Watson Station gathering enhancement facilities. In
pursuing these rehearing issues, complainants seek prospective rate reductions
aggregating approximately $10 million per year.
On March 16, 2000, SFPP filed an application with the CPUC seeking
authority to justify its rates for intrastate transportation of refined
petroleum products on competitive, market-based conditions rather than on
traditional, cost-of-service analysis.
On April 10, 2000, ARCO and Mobil filed a new complaint with the CPUC
asserting that SFPP's California intrastate rates are not just and reasonable
based on a 1998 test year and requesting the CPUC to reduce SFPP's rates
prospectively. The amount of the reduction in SFPP rates sought by the
complainants is not discernible from the complaint.
The rehearing complaint was heard by the CPUC in October 2000 and the April
2000 complaint and SFPP's market-based application were heard by the CPUC in
February 2001. All three matters stand submitted as of April 13, 2001, and a
decision addressing the submitted matters is expected within three to four
months.
The CPUC has recently issued a resolution approving a 2001 request by SFPP
to raise its California rates to reflect increased power costs. The resolution
approving the requested rate increase also requires SFPP to submit cost data for
2001, 2002, and 2003 to assist the CPUC in determining whether SFPP's overall
rates for California intrastate transportation
16
services are reasonable. The resolution reserves the right to require refunds,
from the date of issuance of the resolution, to the extent the CPUC's analysis
of cost data to be submitted by SFPP demonstrates that SFPP's California
jurisdictional rates are unreasonable in any fashion.
There is no way to quantify the potential extent to which the CPUC could
determine that SFPP's existing California rates are unreasonable or estimate the
amount of dollars potentially subject to refund if the draft order is adopted by
the CPUC. SFPP believes that if it is required by the CPUC to submit cost data
in justification of its rates that representative data will indicate that SFPP's
existing rates for California intrastate services remain reasonable and that no
refunds are justified.
We believe that the resolution of such matters will not have a material
adverse effect on our business, financial position or results of operations.
FERC Order 637
Kinder Morgan Interstate Gas Transmission LLC
On June 15, 2000, Kinder Morgan Interstate Gas Transmission LLC made its
filing to comply with FERC's Orders 637 and 637-A. That filing contained KMIGT's
compliance plan to implement the changes required by FERC dealing with the way
business is conducted on interstate natural gas pipelines. All interstate
natural gas pipelines were required to make such compliance filings, according
to a schedule established by FERC. From October 2000 through June 2001, KMIGT
held a series of technical and phone conferences to identify issues, obtain
input, and modify its Order 637 compliance plan, based on comments received from
FERC staff and other interested parties and shippers. On June 19, 2001, KMIGT
received a letter from FERC encouraging it to file revised pro-forma tariff
sheets, which reflected the latest discussions and input from parties into its
Order 637 compliance plan. KMIGT made such a revised Order 637 compliance filing
on July 13, 2001. The July 13, 2001 filing contained little substantive change
from the original pro-forma tariff sheets that KMIGT originally proposed on June
15, 2000. On October 19, 2001, KMIGT received an order from FERC, addressing its
July 13, 2001 Order 637 compliance plan. In the Order addressing the July 13,
2001 compliance plan, KMIGT's plan was accepted, but KMIGT was directed to make
several changes to its tariff, and in doing so, was directed that it could not
place the revised tariff into effect until further order of the FERC. KMIGT
filed its compliance filing with the October 19, 2001 Order on November 19, 2001
and also filed a request for rehearing/clarification of the FERC's October 19,
2001 Order on November 19, 2001. The November 19, 2001 compliance filing has
been protested by several parties. KMIGT filed responses to those protests on
December 14, 2001. At this time, it is unknown when this proceeding will be
finally resolved. The full impact of implementation of Order 637 on the KMIGT
system is under evaluation. We believe that these matters will not have a
material adverse effect on our business, financial position or results of
operations.
Separately, numerous petitioners, including KMIGT, have filed appeals of
Order 637 in the D.C. Circuit, potentially raising a wide array of issues
related to Order 637 compliance. Initial briefs were filed on April 6, 2001,
addressing issues contested by industry participants. Oral arguments on the
appeals were held before the courts in December 2001. On April 5, 2002, the D.C.
Circuit issued an order largely affirming Order Nos. 637, et seq. The D.C.
Circuit remanded the FERC's decision to impose a 5-year cap on bids that an
existing shipper would have to match in the right of first refusal process. The
D.C. Circuit also remanded the FERC's decision to allow forward-hauls and
backhauls to the same point. Finally, the D.C. Circuit held that several aspects
of the FERC's segmentation policy and its policy on discounting at alternate
points were not ripe for review. The FERC has requested comments from the
industry with respect to the issues remanded by the D.C. Circuit. They were due
July
17
30, 2002.
On October 31, 2002, the FERC issued an order in response to the D.C.
Circuit's remand of certain Order 637 issues. The order:
o eliminated the requirement of a 5-year cap on bid terms that an
existing shipper would have to match in the right of first refusal
process, and found that no term matching cap at all is necessary given
existing regulatory controls;
o affirmed FERC's policy that a segmented transaction consisting of both
a forwardhaul up to contract demand and a backhaul up to contract
demand to the same point is permissible; and
o accordingly required, under Section 5 of the NGA, pipelines that the
FERC had previously found must permit segmentation on their systems to
file tariff revisions within 30 days to permit such segmented
forwardhaul and backhaul transactions to the same point.
Trailblazer Pipeline Company
On August 15, 2000, Trailblazer Pipeline Company made a filing to comply
with FERC's Order Nos. 637 and 637-A. Trailblazer's compliance filing reflected
changes in:
o segmentation;
o scheduling for capacity release transactions;
o receipt and delivery point rights;
o treatment of system imbalances;
o operational flow orders;
o penalty revenue crediting; and
o right of first refusal language.
On October 15, 2001, FERC issued its order on Trailblazer's Order No. 637
compliance filing. FERC approved Trailblazer's proposed language regarding
operational flow orders and the right of first refusal, but is requiring
Trailblazer to make changes to its tariff related to the other issues listed
above. Trailblazer anticipates no adverse impact on its business as a result of
the implementation of Order No. 637.
On November 14, 2001, Trailblazer made its compliance filing pursuant to
the FERC order of October 15, 2001. That compliance filing has been protested.
Separately, also on November 14, 2001, Trailblazer filed for rehearing of that
FERC order. These pleadings are pending FERC action.
Standards of Conduct Rulemaking
On September 27, 2001, FERC issued a Notice of Proposed Rulemaking in
Docket No. RM01-10 in which it proposed new rules governing the interaction
between an interstate natural gas pipeline and its affiliates. If adopted as
proposed, the Notice of Proposed Rulemaking could be read to limit
communications between KMIGT, Trailblazer and their respective affiliates. In
addition, the Notice could be read to require separate staffing of KMIGT and its
affiliates, and Trailblazer and its affiliates. Comments on the Notice of
Proposed Rulemaking were due December 20, 2001. Numerous parties, including
KMIGT, have filed comment on the Proposed Standards of Conduct Rulemaking. On
May 21, 2002, FERC held a technical conference dealing with the FERC's proposed
changes in the Standard of Conduct Rulemaking. On June 28, 2002, KMIGT and
numerous other parties flied additional written comments under a procedure
adopted at the technical conference. The Proposed Rulemaking is awaiting further
FERC action. We believe that these matters, as finally adopted, will not have a
material adverse effect on our business, financial position or results of
operations.
The FERC also issued a Notice of Proposed Rulemaking in Docket No.
RM02-14-000 in which it proposed new regulations for cash management practices,
including establishing limits on the amount of funds that can be swept from a
regulated subsidiary to a non-regulated parent company. Kinder Morgan Interstate
Gas Transmission LLC filed comments on August 28, 2002. We believe that these
matters, as finally adopted, will not have a material adverse effect on our
business, financial position or results of operations.
In addition to the matters described above, we may face additional
challenges to our rates in the future. Shippers on our pipelines do have rights
to challenge the rates we charge under certain circumstances prescribed by
applicable regulations. There can be no assurance that we will not face
challenges to the rates we receive for services on our pipeline systems in the
future. In addition, since many of our assets are subject to regulation, we are
subject to potential future changes in applicable rules and regulations that may
have an adverse effect on our business, financial position or results of
operations.
Southern Pacific Transportation Company Easements
SFPP and Southern Pacific Transportation Company are engaged in a judicial
reference proceeding to determine the extent, if any, to which the rent payable
by SFPP for the use of pipeline easements on rights-of-way held by SPTC should
be adjusted pursuant to existing contractual arrangements (Southern Pacific
Transportation Company vs. Santa Fe Pacific Corporation, SFP Properties, Inc.,
Santa Fe Pacific Pipelines, Inc., SFPP, L.P., et al., Superior Court of the
State of California for the County of San Francisco, filed August 31, 1994).
Although SFPP received a favorable ruling from the trial court in May 1997,
in September 1999, the California Court of Appeals remanded the case back to the
trial court for further proceeding. SFPP claims that the rent payable for each
of the years 1994 through 2004 should be approximately $4.4 million and SPTC
claims it should be approximately $15.0 million. We believe SPTC's position in
this case is without merit and we have set aside reserves that we believe are
adequate to address any reasonably foreseeable outcome of this matter. As of
mid-October 2002, the matter is currently in trial.
Carbon Dioxide Litigation
Kinder Morgan CO2 Company, L.P. directly or indirectly through its
ownership interest in the Cortez Pipeline Company, along with other entities, is
a defendant in several actions in which the plaintiffs allege that the
defendants undervalued carbon dioxide produced from the McElmo Dome field and
overcharged for transportation costs, thereby allegedly underpaying royalties
and severance tax payments. The plaintiffs, who are seeking monetary damages and
injunctive relief, are comprised of royalty, overriding royalty and small share
working interest owners who claim that they were underpaid by the defendants.
These cases are: CO2 Claims Coalition, LLC v. Shell Oil Co., et al., No.
96-Z-2451 (U.S.D.C. Colo. filed 8/22/96); Rutter & Wilbanks et al. v. Shell Oil
Co., et al., No. 00-Z-1854 (U.S.D.C. Colo. filed 9/22/00); Watson v. Shell Oil
Co., et al., No. 00-Z-1855 (U.S.D.C. Colo. filed 9/22/00); Ainsworth et al. v.
Shell Oil Co., et al., No. 00-Z-1856 (U.S.D.C. Colo. filed 9/22/00); United
18
States ex rel. Crowley v. Shell Oil Company, et al., No. 00-Z-1220
(U.S.D.C. Colo. filed 6/13/00); Shell Western E&P Inc. v. Bailey, et al., No
98-28630 (215th Dist. Ct. Harris County, Tex. filed 6/17/98); Shores, et al. v.
Mobil Oil Corporation, et al., No. GC-99-01184 (Texas Probate Court, Denton
County filed 12/22/99); First State Bank of Denton v. Mobil Oil Corporation, et
al., No. PR-8552-01 (Texas Probate Court, Denton County filed 3/29/01); and
Celeste C. Grynberg v. Shell Oil Company, et al., No. 98-CV-43 (Colo. Dist. Ct.
Montezuma County filed 3/21/98).
At a hearing conducted in the United States District Court for the District
of Colorado on April 8, 2002, the Court orally announced that it had approved
the certification of proposed plaintiff classes and approved a proposed
settlement in the CO2 Claims Coalition, LLC, Rutter & Wilbanks, Watson,
Ainsworth and United States ex rel. Crowley cases. The Court entered a written
order approving the Settlement on May 6, 2002; plaintiffs counsel representing
Shores, et al. appealed the court's decision to the 10th Circuit Court of
Appeals.
RSM Production Company, et al. v. Kinder Morgan Energy Partners, L.P., et
al.
Cause No. 4519, in the District Court, Zapata County Texas, 49th Judicial
District. On October 15, 2001, Kinder Morgan Energy Partners, L.P. was served
with the First Supplemental Petition filed by RSM Production Corporation on
behalf of the County of Zapata, State of Texas and Zapata County Independent
School District as plaintiffs. Kinder Morgan Energy Partners, L.P. was sued in
addition to 15 other defendants, including two other Kinder Morgan affiliates.
Certain entities we acquired in the Kinder Morgan Tejas acquisition are also
defendants in this matter. The Petition alleges that these taxing units relied
on the reported volume and analyzed heating content of natural gas produced from
the wells located within the appropriate taxing jurisdiction in order to
properly assess the value of mineral interests in place. The suit further
alleges that the defendants undermeasured the volume and heating content of that
natural gas produced from privately owned wells in Zapata County, Texas. The
Petition further alleges that the County and School District were deprived of ad
valorem tax revenues as a result of the alleged undermeasurement of the natural
gas by the defendants. On December 15, 2001, the defendants filed motions to
transfer venue on jurisdictional grounds. There are no further pretrial
proceedings at this time.
Will Price, et al. v. Gas Pipelines, et al., (f/k/a Quinque Operating Company
et al. v. Gas Pipelines, et al.)
Stevens County, Kansas District Court, Case No. 99 C 30. In May, 1999, three
plaintiffs, Quinque Operating Company, Tom Boles and Robert Ditto, filed a
purported nationwide class action in the Stevens County, Kansas District Court
against some 250 natural gas pipelines and many of their affiliates. The
District Court is located in Hugoton, Kansas. Certain entities we acquired in
the Kinder Morgan Tejas acquisition are also defendants in this matter. The
Petition (recently amended) alleges a conspiracy to underpay royalties, taxes
and producer payments by the defendants' undermeasurement of the volume and
heating content of natural gas produced from nonfederal lands for more than
twenty-five years. The named plaintiffs purport to adequately represent the
interests of unnamed plaintiffs in this action who are comprised of the nation's
gas producers, State taxing agencies and royalty, working and overriding owners.
The plaintiffs seek compensatory damages, along with statutory penalties, treble
damages, interest, costs and fees from the defendants, jointly and severally.
This action was originally filed on May 28, 1999 in Kansas State Court in
Stevens County, Kansas as a class action against approximately 245 pipeline
companies and their affiliates, including certain Kinder Morgan entities.
Subsequently, one of the defendants removed the action to Kansas Federal
District Court and the case was styled as Quinque Operating Company, et al. v.
Gas Pipelines, et al., Case No. 99-1390-CM, United States District Court for the
District of Kansas. Thereafter, we filed a motion with the Judicial Panel for
Multidistrict Litigation to consolidate this action for pretrial purposes with
the Grynberg False Claim Act cases referred to below, because of common factual
questions. On April 10, 2000, the MDL Panel ordered that this case be
consolidated with the Grynberg federal False Claims Act cases. On January 12,
2001, the Federal District Court of Wyoming issued an oral ruling remanding the
case back to the State Court in Stevens County, Kansas. The Court in Kansas has
issued a case management order addressing the initial phasing of the case. In
this initial phase, the court will rule on motions to dismiss (jurisdiction and
sufficiency of pleadings), and if the action is not dismissed, on class
certification. Merits discovery has been stayed. Recently, the defendants filed
a motion to dismiss on grounds other than personal jurisdiction, which was
denied by the Court in August, 2002. The Motion to Dismiss for lack of Personal
Jurisdiction of the nonresident defendants has been briefed and is awaiting
decision. The current named plaintiffs are Will Price, Tom Boles, Cooper Clark
Foundation and Stixon Petroleum, Inc. Quinque Operating Company has been dropped
from the action as a named plaintiff.
United States of America, ex rel., Jack J. Grynberg v. K N Energy
Civil Action No. 97-D-1233, filed in the U.S. District Court, District of
Colorado. This action was filed on June 9, 1997 pursuant to the federal False
Claim Act and involves allegations of mismeasurement of natural gas produced
from federal and Indian lands. The Department of Justice has decided not to
intervene in support of the action. The complaint is part of a larger series of
similar complaints filed by Mr. Grynberg against 77 natural gas pipelines
(approximately 330 other defendants). Certain entities we acquired in the Kinder
Morgan Tejas acquisition are also defendants in this matter. An earlier single
action making substantially similar allegations against the pipeline industry
was dismissed by Judge Hogan of the U.S. District Court for the District of
Columbia on grounds of improper joinder and lack of jurisdiction. As a result,
Mr. Grynberg filed individual complaints in various courts throughout the
country. In 1999, these cases were consolidated by the Judicial Panel for
Multidistrict Litigation, and transferred to the District of Wyoming. The MDL
case is called In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293.
Motions to Dismiss were filed and an oral argument on the Motion to Dismiss
occurred on March 17, 2000. On July 20, 2000 the United States of America filed
a motion to dismiss those claims by Grynberg that deal with the manner in which
defendants valued gas produced from federal leases. Judge Downes denied the
defendant's motion to dismiss on May 18, 2001. Pretrial proceedings are
underway.
Sweatman and Paz Gas Corporation v. Gulf Energy Marketing, LLC, et al.
Mel R. Sweatman and Paz Gas Corporation vs. Gulf Energy Marketing, LLC, et
al. On July 25, 2002, we were served with this suit for breach of contract,
tortious interference with existing contractual relationships, conspiracy to
commit tortuous interference and interference with prospective business
relationship. Mr. Sweatman and Paz Gas Corporation claim that, in connection
with our acquisition of Tejas Gas, LLC, we wrongfully caused gas volumes to be
shipped on our Kinder Morgan Texas Pipeline system instead of our Kinder Morgan
Tejas system. Mr. Sweatman and Paz Gas Corporation allege that this action
eliminated profit on Kinder Morgan Tejas, a portion of which Mr. Sweatman and
Paz Gas Corporation claim they are entitled under an agreement with a subsidiary
of ours acquired in the Tejas Gas acquisition. We have filed a motion to remove
the case from venue in Dewitt County, Texas to Harris County, Texas, and a
hearing has been set for November 2002 to argue this motion. Based on the
19
information available to date and our preliminary investigation, we believe this
suit is without merit and we intend to defend it vigorously.
Maher et ux. v. Centerpoint Energy, Inc. d/b/a Reliant Energy,
Incorporated, Reliant Energy Resources Corp., Entex Gas Marketing Company,
Kinder Morgan Texas Pipeline, L.P., Kinder Morgan Energy Partners, L.P., Houston
Pipeline Company, L.P. and AEP Gas Marketing, L.L.C., No. 30875 (District Court,
Wharton County Texas).
On October 21, 2002, Kinder Morgan Texas Pipeline, L.P. and Kinder Morgan
Energy Partners, L.P. were served with the above-entitled Complaint. A First
Amended Complaint was served on October 23, 2002, adding additional defendants
Kinder Morgan G.P., Inc., Kinder Morgan Tejas Pipeline GP, Inc., Kinder Morgan
Texas Pipeline GP, Inc., Tejas Gas, LLC and HPL GP, LLC. The First Amended
Complaint purports to bring a class action on behalf of those Texas residents
who purchased natural gas for residential purposes from the so-called "Reliant
Defendants" in Texas at any time during the period encompassing "at least the
last ten years."
The Complaint alleges that Reliant Energy Resources Corp., by and through
its affiliates, has artificially inflated the price charged to residential
consumers for natural gas that it allegedly purchased from the non-Reliant
defendants, including the above-listed Kinder Morgan entities. The Complaint
further alleges that in exchange for Reliant Energy Resources Corp.'s purchase
of natural gas at above market prices, the non-Reliant defendants, including the
above-listed Kinder Morgan entities, sell natural gas to Entex Gas Marketing
Company at prices substantially below market, which in turn sells such natural
gas to commercial and industrial consumers and gas marketers at market price.
The Complaint purports to assert claims for fraud, violations of the Texas
Deceptive Trade Practices Act, and violations of the Texas Utility Code against
some or all of the Defendants, and civil conspiracy against all of the
defendants, and seeks relief in the form of, inter alia, actual, exemplary and
statutory damages, civil penalties, interest, attorneys' fees and a constructive
trust ab initio on any and all sums which allegedly represent overcharges by
Reliant and Reliant Energy Resources Corp.
The Kinder Morgan defendants' answers to this Complaint have not yet become
due. Based on the information available to date and our preliminary
investigation, the Kinder Morgan defendants believe that the claims against them
are without merit and intend to defend against them vigorously.
Marie Snyder, et al v. City of Fallon, United States Department of the
Navy, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Speedway Gas
Station and John Does I-X, No. cv-N-02-0251-ECR-RAM (United States District
Court, District of Nevada).
On July 9, 2002, we were served with a purported Complaint for Class Action
in which the plaintiffs, on behalf of themselves and others similarly situated,
assert that a leukemia cluster has developed in the City of Fallon, Nevada. The
Complaint alleges that the plaintiffs have been exposed to unspecified
"environmental carcinogens" at unspecified times in an unspecified manner and
are therefore "suffering a significantly increased fear of serious disease." The
plaintiffs seek a certification of a class of all persons in Nevada who have
lived for at least three months of their first ten years of life in the City of
Fallon between the years 1992 and the present who have not been diagnosed with
leukemia.
The Complaint purports to assert causes of action for nuisance and "knowing
concealment, suppression, or omission of material facts" against all defendants,
and seeks relief in the form of "a court-supervised trust fund, paid for by
defendants, jointly and severally, to finance a medical monitoring program to
deliver services [to members of the purported class] that include, but are not
limited to, testing, preventative screening and surveillance for conditions
resulting from, or which can potentially result from exposure to environmental
carcinogens," incidental damages, and attorneys' fees and costs.
We responded to the Complaint with a Motion to Dismiss on the grounds that
it fails to state a claim against us upon which relief can be granted. This
motion is currently pending before the court. Based on the information available
to date and our preliminary investigation, we believe that the claims against us
are without merit and intend to defend against them vigorously.
Although no assurances can be given, we believe that we have meritorious
defenses to all of these actions, that, to the extent an assessment of the
matter is possible, we have established an adequate reserve to cover potential
liability, and that these matters will not have a material adverse effect on
our business, financial position or results of operations.
20
Environmental Matters
We are subject to environmental cleanup and enforcement actions from time
to time. In particular, the federal Comprehensive Environmental Response,
Compensation and Liability Act (CERCLA) generally imposes joint and several
liability for cleanup and enforcement costs on current or predecessor owners and
operators of a site, without regard to fault or the legality of the original
conduct. Our operations are also subject to federal, state and local laws and
regulations relating to protection of the environment. Although we believe our
operations are in substantial compliance with applicable environmental
regulations, risks of additional costs and liabilities are inherent in pipeline
and terminal operations, and there can be no assurance that we will not incur
significant costs and liabilities. Moreover, it is possible that other
developments, such as increasingly stringent environmental laws, regulations and
enforcement policies there under, and claims for damages to property or persons
resulting from our operations, could result in substantial costs and liabilities
to us.
We are currently involved in the following governmental proceedings related
to compliance with environmental regulations associated with our assets and have
established a reserve to address the costs associated with the cleanup:
o one cleanup ordered by the United States Environmental Protection
Agency related to ground water contamination in the vicinity of SFPP's
storage facilities and truck loading terminal at Sparks, Nevada;
o several ground water hydrocarbon remediation efforts under
administrative orders issued by the California Regional Water Quality
Control Board and two other state agencies;
o groundwater and soil remediation efforts under administrative orders
issued by various regulatory agencies on those assets purchased from
GATX Corporation, comprising Kinder Morgan Liquids Terminals LLC,
CALNEV Pipe Line LLC and Central Florida Pipeline LLC; and
o a ground water remediation effort taking place between Chevron,
Plantation Pipe Line Company and the Alabama Department of
Environmental Management.
In addition, we are from time to time involved in civil proceedings
relating to damages alleged to have occurred as a result of accidental leaks or
spills of refined petroleum products, natural gas liquids, natural gas and
carbon dioxide.
Furthermore, our review of assets related to Kinder Morgan Interstate Gas
Transmission LLC indicates possible environmental impacts from petroleum and
used oil releases into the soil and groundwater at nine sites. Additionally, our
review of assets related to Kinder Morgan Texas Pipeline indicates possible
environmental impacts from petroleum releases into the soil and groundwater at
six sites. Further delineation and remediation of any environmental impacts from
these matters will be conducted. Reserves have been established to address the
closure of these issues.
On October 2, 2001, the jury rendered a verdict in the case of Walter
Chandler v. Plantation Pipe Line Company. The jury awarded the plaintiffs a
total of $43.8 million. The judge reduced the award to $42.6 million due to a
prior settlement with the plaintiffs by a third party. The verdict was divided
with the following award of damages:
o $0.3 million compensatory damages for property damage to the Evelyn
Chandler Trust;
o $4.1 million compensatory damages to Walter (Buster) Chandler;
o $1.2 million compensatory damages to Clay Chandler; and
o $37 million punitive damages.
Plantation has filed post judgment motions and an appeal of the verdict.
The appeal of this case will be directly heard by the Alabama Supreme Court. It
is anticipated that a decision by the Alabama Supreme Court will be received
within the next six to eight months.
This case was filed in April 1997 by the landowner (Evelyn Chandler Trust)
and two residents of the property (Buster Chandler and his son, Clay Chandler).
The suit was filed against Chevron, Plantation and two individuals. The two
individuals were later dismissed from the suit. Chevron settled with the
plaintiffs in December 2000. The property and residences are directly across the
street from the location of a former Chevron products terminal. The Plantation
pipeline system traverses the Chevron terminal property. The suit alleges that
gasoline released from the terminal and pipeline contaminated the groundwater
under the plaintiffs' property. As noted above, a current remediation effort is
taking place between Chevron, Plantation and Alabama Department of Environmental
Management.
In addition to the Chandler case, in 1999, other individuals living in
close proximity to the Chandlers filed eight lawsuits against Plantation,
Chevron and an environmental consulting firm, CH2MHill. These individuals live
in a community called Greenridge, which is outside of Moundville, Alabama. The
eight lawsuits were filed in and are currently pending in the circuit court of
Hale County, Alabama. The Greenridge plaintiffs allege property damage from
groundwater contaminated by petroleum hydrocarbons. The Greenridge plaintiffs
also allege personal injuries from exposure to fumes from contaminated
groundwater that discharges to the swamp near their houses. The eight lawsuits
were consolidated into one trial that was scheduled for December 2002 but has
been continued. A new trial date has not been set but is anticipated during
2003. Plantation believes that the ultimate resolution of the Greenridge cases
will not have a material adverse effect on its business, financial position or
results of operations.
21
Although no assurance can be given, we believe that the ultimate resolution
of the environmental matters set forth in this note will not have a material
adverse effect on our business, financial position or results of operations. We
have recorded a total reserve for environmental claims in the amount of $59.7
million at September 30, 2002. As of September 30, 2002, we were not able to
reasonably estimate when the eventual settlements of these claims will occur.
Other
We are a defendant in various lawsuits arising from the day-to-day
operations of our businesses. Although no assurance can be given, we believe,
based on our experiences to date, that the ultimate resolution of such items
will not have a material adverse impact on our business, financial position or
results of operations. In addition, since many of our assets are subject to
regulation, we are subject to potential future challenges to our rates and to
changes in applicable rules and regulations that may have an adverse effect on
our business, financial position or results of operations.
4. Two-for-One Common Unit Split
On July 18, 2001, Kinder Morgan Management, LLC, the delegate of our
general partner, approved a two-for-one unit split of its outstanding shares and
our outstanding common units representing limited partner interests in us. The
common unit split entitled our common unitholders to one additional common unit
for each common unit held. Our partnership agreement provides that when a split
of our common units occurs, a unit split on our class B units and our i-units
will be effected to adjust proportionately the number of our class B units and
i-units. The two-for-one split occurred on August 31, 2001 to unitholders of
record on August 17, 2001. All references to the number of Kinder Morgan
Management, LLC shares, the number of our limited partner units and per unit
amounts in our consolidated financial statements and related notes, have been
restated to reflect the effect of the split for all periods presented.
5. Distributions
On August 14, 2002, we paid a cash distribution for the quarterly period
ended June 30, 2002, of $0.61 per unit to our common unitholders and to our
class B unitholders. Kinder Morgan Management, LLC, our sole i-unitholder,
received 619,585 additional i-units based on the $0.61 cash distribution per
common unit. The distributions were declared on July 17, 2002, payable to
unitholders of record as of July 31, 2002.
On October 16, 2002, we declared a cash distribution for the quarterly
period ended September 30, 2002, of $0.61 per unit. The distribution will be
paid on or before November 14, 2002, to unitholders of record as of October 31,
2002. Our common unitholders and class B unitholders will receive cash. Our sole
i-unitholder will receive a distribution in the form of additional i-units based
on the $0.61 distribution per common unit. The number of i-units distributed
will be 937,658. For each outstanding i-unit that Kinder Morgan Management, LLC
holds, a fraction of an i-unit will be issued. The fraction is determined by
dividing:
o the cash amount distributed per common unit
by
o the average of Kinder Morgan Management's shares' closing market
prices from October 15-28, 2002, the ten consecutive trading days
preceding the date on which the shares began to trade ex-dividend
under the rules of the New York Stock Exchange.
6. Intangibles
Effective January 1, 2002, we adopted Statement of Financial Accounting
Standards No. 141 "Business Combinations" and Statement of Financial Accounting
Standards No. 142 "Goodwill and Other Intangible Assets". These accounting
pronouncements require that we prospectively cease amortization of all
intangible assets having indefinite useful economic lives. Such assets,
including goodwill, are not to be amortized until their lives are determined to
be finite. A recognized intangible asset with an indefinite useful life should
be tested for impairment annually or on an interim basis if events or
circumstances indicate that the fair value of the asset has decreased below its
carrying value. We completed this initial transition impairment test in June
2002 and determined that our goodwill was not impaired as of January 1, 2002.
22
Our intangible assets include goodwill, lease value, contracts and
agreements. All of our intangible assets having definite lives are being
amortized on a straight-line basis over their estimated useful lives. SFAS Nos.
141 and 142 also require that we disclose the following information related to
our intangible assets still subject to amortization and our goodwill (in
thousands):
Sept. 30, Dec. 31,
2002 2001
--------- ---------
Goodwill $ 662,636 $ 566,633
Accumulated amortization (19,899) (19,899)
--------- ---------
Goodwill, net 642,737 546,734
--------- ---------
Lease value 6,124 6,124
Contracts and other 10,767 10,739
Accumulated amortization (335) (200)
--------- ---------
Other intangibles, net 16,556 16,663
--------- ---------
Total intangibles, net $ 659,293 $ 563,397
========= =========
Changes in the carrying amount of goodwill for the nine months ended
September 30, 2002 are summarized as follows (in thousands):
Products Natural Gas CO2
Pipelines Pipelines Pipelines Terminals Total
--------- --------- --------- --------- -----
Balance at Dec. 31, 2001 $ 262,765 $ 87,452 $ 46,101 $ 150,416 $546,734
Goodwill acquired 417 -- -- -- 417
Goodwill dispositions, -- -- -- -- --
net
Impairment losses -- -- -- -- --
--------- --------- --------- --------- ---------
Balance at Mar. 31, 2002 $ 263,182 $ 87,452 $ 46,101 $ 150,416 $ 547,151
========= ========= ========= ========= =========
Goodwill acquired -- 83,262 -- 5,320 88,582
Goodwill dispositions, -- -- -- -- --
net
Impairment losses -- -- -- -- --
--------- --------- --------- --------- ---------
Balance at June 30, 2002 $ 263,182 $ 170,714 $ 46,101 $ 155,736 $ 635,733
========= ========= ========= ========= =========
Goodwill acquired -- 3,432 -- 3,572 7,004
Goodwill dispositions, -- -- -- -- --
net
Impairment losses -- -- -- -- --
--------- --------- --------- --------- ---------
Balance at Sept. 30, 2002
$ 263,182 $ 174,146 $ 46,101 $ 159,308 $ 642,737
========= ========= ========= ========= =========
Amortization expense on intangibles, including amortization of excess
intangible costs of equity investments, consists of the following (in
thousands):
Three Months Ended Sept. 30, Nine Months Ended Sept. 30,
2002 2001 2002 2001
--------- --------- --------- ---------
Goodwill $ -- $ 3,646 $ -- $ 9,613
Lease value 35 1,161 105 3,954
Contracts and
other 10 10 30 30
-------- -------- -------- --------
$ 45 $ 4,817 $ 135 $ 13,597
======== ======== ======== ========
Our weighted average amortization period for our intangible assets is
approximately 42 years. The following table shows the estimated amortization
expense for these assets for each of the five succeeding fiscal years (in
thousands):
2003 $180
2004 $180
2005 $180
2006 $180
2007 $180
Had SFAS No. 142 been in effect prior to January 1, 2002, our reported
limited partners' interest in net income and net income per unit would have been
as follows (in thousands, except per unit amounts):
23
Three Months Ended Nine Months Ended
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2002 2001 2002 2001
---- ---- ---- ----
Reported limited partners'
interest in net income $ 87,800 $ 60,968 $ 246,722 $ 174,633
Add: limited partners' interest
in goodwill amortization -- 3,609 -- 9,516
-------- -------- --------- ---------
Adjusted limited partners'
interest in net income $ 87,800 $ 64,577 $ 246,722 $ 184,149
======== ======== ========= =========
Basic limited partners' net
income per unit:
Reported net income $ 0.50 $ 0.37 $ 1.46 $ 1.16
Goodwill amortization -- 0.02 -- 0.06
------ ------ ------ ------
Adjusted net income $ 0.50 $ 0.39 $ 1.46 $ 1.22
Diluted limited partners' net
income per unit:
Reported net income $ 0.50 $ 0.37 $ 1.46 $ 1.16
Goodwill amortization -- 0.02 -- 0.06
------ ------ ------ ------
Adjusted net income $ 0.50 $ 0.39 $ 1.46 $ 1.22
====== ====== ====== ======
7. Debt
Our debt and credit facilities as of September 30, 2002, consisted
primarily of:
o a $750 million unsecured 364-day credit facility due October 23, 2002
(subsequently replaced October 16, 2002 by a $494 million unsecured
364-day credit facility due October 14, 2003);
o a $300 million unsecured five-year credit facility due September 29,
2004 (subsequently replaced October 16, 2002 by a $411.7 million
unsecured three-year credit facility due October 15, 2005);
o $79.5 million of Series F First Mortgage Notes due December 2004 (our
subsidiary, SFPP, L.P. is the obligor on the notes);
o $200 million of 8.00% Senior Notes due March 15, 2005;
o $40 million of Plaquemines, Louisiana Port, Harbor, and Terminal
District Revenue Bonds due March 15, 2006 (our subsidiary, International
Marine Terminals, is the obligor on the bonds);
o $250 million of 5.35% Senior Notes due August 15, 2007; o $30 million of
7.84% Senior Notes, with a final maturity of July 2008 (our subsidiary,
Central Florida Pipe Line LLC, is the obligor on the notes);
o $250 million of 6.30% Senior Notes due February 1, 2009; o $250 million
of 7.50% Senior Notes due November 1, 2010; o $700 million of 6.75%
Senior Notes due March 15, 2011;
o $450 million of 7.125% Senior Notes due March 15, 2012;
o $25 million of New Jersey Economic Development Revenue Refunding Bonds
due January 15, 2018 (our subsidiary, Kinder Morgan Liquids Terminals
LLC, is the obligor on the bonds);
o $87.9 million of Industrial Revenue Bonds with final maturities ranging
from September 2019 to December 2024 (our subsidiary, Kinder Morgan
Liquids Terminals LLC, is the obligor on the bonds);
o $23.7 million of tax-exempt bonds due 2024 (our subsidiary, Kinder
Morgan Operating L.P. "B", is the obligor on the bonds);
o $300 million of 7.40% Senior Notes due March 15, 2031; o $300 million
of 7.75% Senior Notes due March 15, 2032;
o $500 million of 7.30% Senior Notes due August 15, 2033; and
o a $1.05 billion short-term commercial paper program.
None of our debt or credit facilities are subject to payment acceleration
as a result of any change to our credit ratings. However, the margin that we pay
with respect to LIBOR based borrowings under our credit facilities is tied to
our credit ratings.
On August 6, 2002, Kinder Morgan Management, LLC issued in a public
offering, an additional 12,478,900 of its shares, including 478,900 shares upon
exercise by the underwriters of an over-allotment option, at a price of $27.50
per share, less commissions and underwriting expenses. The net proceeds from the
offering were used to buy i-units from us. After commissions and underwriting
expenses, we received net proceeds of approximately $331.2 million for the
issuance of 12,478,900 i-units. We used the proceeds from the i-unit issuance to
reduce the borrowings under our commercial paper program.
24
Our outstanding short-term debt at September 30, 2002, consisted of:
o $132.1 million of commercial paper borrowings;
o $42.5 million under the SFPP, L.P. 10.7% First Mortgage Notes; and
o $5.0 million under the Central Florida Pipeline LLC Notes.
We intend and have the ability to refinance our $179.6 million of short-
term debt on a long-term basis under our unsecured long-term credit facility.
Accordingly, such amounts have been classified as long-term debt in our
accompanying consolidated balance sheet. We do not anticipate any liquidity
problems. Our average interest rate for outstanding borrowings during the third
quarter of 2002 was approximately 5.00% per annum.
For additional information regarding our debt facilities, see Note 9 to our
consolidated financial statements included in our Annual Report on Form 10-K for
the year ended December 31, 2001.
Credit Facilities
On June 30, 2002, we had three existing bank credit facilities:
o a $750 million unsecured 364-day credit facility due October 23, 2002;
o a $200 million unsecured 364-day credit facility due February 20, 2003;
and
o a $300 million unsecured five-year credit facility due September
29, 2004.
No borrowings were outstanding under our three credit facilities at June
30, 2002. In August 2002, upon the completion of our i-unit equity sale, we
terminated, under the terms of the agreement, our $200 million unsecured 364-day
credit facility that was due February 20, 2003. At September 30, 2002, no
borrowings were outstanding under our remaining two credit facilities.
On October 16, 2002, we announced that we had successfully renegotiated our
bank credit facilities by replacing our $750 million unsecured 364-day credit
facility due October 23, 2002 and our $300 million unsecured five-year credit
facility due September 29, 2004 with two new credit facilities. The new
facilities include:
o a $494.0 million unsecured 364-day credit facility due October 14, 2003;
and
o a $411.7 million unsecured three-year credit facility due October 15,
2005.
The amount available for borrowing under our credit facilities is reduced
by a $23.7 million letter of credit that supports Kinder Morgan Operating L.P.
"B"'s tax-exempt bonds and by our outstanding commercial paper borrowings.
Furthermore, in addition to the borrowing capacity of this $905.7 million, we
may close on additional commitments during the fourth quarter of 2002.
Our new credit facilities are with a syndicate of financial institutions.
Wachovia Bank, National Association is the administrative agent under both
credit facilities. The terms of our two new credit facilities are substantially
similar to the terms of our previous credit facilities. However, our prior
credit facilities limited debt as a multiple of EBITDA (earnings before
interest, taxes and depreciation expenses) for the prior four quarters to an
amount not greater than 4.0. Our new facilities have increased the limit of that
multiple to an amount not greater than 5.0. Interest on the two credit
facilities accrues at our option at a floating rate equal to either:
o the administrative agent's base rate (but not less than the Federal
Funds Rate, plus 0.5%); or
o LIBOR, plus a margin, which varies depending upon the credit rating of
our long-term senior unsecured debt.
Our new three-year credit facility also permits us to obtain bids for fixed
rate loans from members of the lending syndicate.
Senior Notes
Under an indenture dated August 19, 2002, and a First Supplemental
Indenture dated August 23, 2002, we completed a private placement of $750
million in debt securities to qualified institutional buyers in reliance on Rule
144A under the Securities Act of 1933. The indenture is a contract between us
and Wachovia Bank, National Association, which acts as trustee. The notes
represent additional unsecured obligations of ours and rank equally with all of
our unsecured and unsubordinated debt. The notes consist of $500 million in
principal amount of 7.30%
25
Senior Notes due August 15, 2033 and $250 million in principal amount of 5.35%
Senior Notes due August 15, 2007, unless sooner redeemed. The notes are not
entitled to the benefits of a sinking fund.
Although only $500 million aggregate principal amount of the 7.30% notes
and $250 million aggregate principal amount of the 5.35% notes were originally
issued, so long as no Event of Default under the indenture has occurred and is
continuing, we may issue and sell additional notes of either or both series and
with the same terms, without the consent of holders of either series of the
notes. Any additional notes of a series, together with the previously issued
notes of that series, will constitute a single series of notes under the
indenture.
Interest on each series of notes is payable semi-annually in arrears on
February 15 and August 15 of each year. The notes are redeemable, at our option,
at any time at a price equal to 100% of their principal amount plus accrued and
unpaid interest plus a make-whole premium, if any. In no event will the
redemption price ever be less than 100% of the principal amount of the notes
plus accrued interest to the redemption date. In the offering, we received
proceeds, net of underwriting discounts and commissions, of approximately $494.7
million for the 7.30% notes and $248.3 million for the 5.35% notes. The proceeds
were used to reduce the borrowings under our commercial paper program.
At the closing of the offering, we entered into a registration rights
agreement with the initial purchasers pursuant to which we agreed, for the
benefit of the holders of the notes, at our cost, to make an offer to exchange
the original notes for new notes that are substantially identical to the terms
of the original notes of the same series, except that the exchange notes will be
freely transferable and issued free of any covenants regarding exchange and
registration rights. Specifically, we agreed, at our cost,
o within 120 days after the date of original issuance of the original
notes, to file an exchange offer registration statement with the SEC
with respect to the exchange offers for the exchange notes;
o to use our reasonable efforts to cause the exchange offer registration
statement to be declared effective under the Securities Act of 1933
within 210 days after the date of original issuance of the original
notes; and
o to keep the exchange offers open for not less than 30 days, or longer if
required by applicable law.
If we do not accomplish these or certain other actions with respect to the
exchange offer by certain specified dates, the interest rate on the original
notes will be increased until we accomplish those actions. The exchange offer
commenced on October 18, 2002 and is scheduled to expire on November 18, 2002,
unless extended. We do not anticipate that we will pay any additional interest
on the notes.
At September 30, 2002, our unamortized liability balance due on the various
series of our senior notes was as follows (in millions):
8.0% senior notes due March 15, 2005 $ 199.8
5.35% senior notes due August 15, 2007 249.8
6.3% senior notes due February 1, 2009 249.5
7.5% senior notes due November 1, 2010 248.7
6.75% senior notes due March 15, 2011 698.3
7.125% senior notes due March 15, 2012 448.0
7.4% senior notes due March 15, 2031 299.3
7.75% senior notes due March 15, 2032 298.5
7.3% senior notes due August 15, 2033 499.0
-----
Total $3,190.9
========
Interest Rate Swaps
In order to maintain a cost effective capital structure, it is our policy
to borrow funds using a mix of fixed rate debt and variable rate debt. As of
September 30, 2002, we have entered into interest rate swap agreements with a
notional principal amount of $1.95 billion for the purpose of hedging the
interest rate risk associated with our fixed and floating rate debt obligations.
These interest rate swaps have been designated as fair value hedges as
defined by SFAS No. 133. These swaps also meet the conditions required to assume
no ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them
using the "shortcut" method prescribed for fair value hedges by SFAS No. 133.
Accordingly, we adjust the carrying value of each swap to its fair value each
quarter, with an offsetting entry to adjust the carrying value of the debt
securities whose fair value is being hedged. At September 30, 2002, we
recognized an asset of
26
$157.5 million for the net fair value of our swap agreements and we included
this amount with Deferred charges and other assets on the accompanying balance
sheet. At December 31, 2001, we recognized a liability of $5.4 million for the
net fair value of our swap agreements and we included this amount with Other
Long-Term Liabilities and Deferred Credits on the accompanying balance sheet.
For more information on our risk management activities, see Note 10.
Commercial Paper Program
As of June 30, 2002, our commercial paper program provided for the issuance
of up to $1.25 billion of commercial paper. Borrowings under our commercial
paper program reduce the borrowings allowed under our credit facilities. On
August 6, 2002, in conjunction with our issuance of additional i-units and as
previously agreed upon under the terms of our credit facilities, we reduced our
commercial paper program to provide for the issuance of up to $1.05 billion of
commercial paper. As of September 30, 2002, we had $132.1 million of commercial
paper outstanding with an average interest rate of 2.09%.
Trailblazer Pipeline Company Debt
At June 30, 2002, the outstanding balance under Trailblazer's $85.2 million
two-year revolving credit facility was $31.0 million. The revolving credit
facility was to expire on June 29, 2003, however, in late July 2002, we paid the
$31.0 million outstanding balance under Trailblazer's revolving credit facility
and terminated the facility.
Kinder Morgan Operating L.P. "B" Debt
The $23.7 million principal amount of tax-exempt bonds due 2024 were issued
by the Jackson-Union Counties Regional Port District. These bonds bear interest
at a weekly floating market rate. During the third quarter of 2002, the
weighted-average interest rate on these bonds was 1.37% per annum, and at
September 30, 2002, the interest rate was 1.70%. We have an outstanding letter
of credit issued under our credit facilities that supports our tax-exempt bonds.
The letter of credit reduces the amount available for borrowing under our credit
facilities.
International Marine Terminals Debt
As of February 1, 2002, we own a 66 2/3% interest in International Marine
Terminals (IMT) partnership (see Note 2). The principal assets owned by IMT are
dock and wharf facilities financed by the Plaquemines Port, Harbor and Terminal
District (Louisiana) $40,000,000 Adjustable Rate Annual Tender Port Facilities
Revenue Refunding Bonds (International Marine Terminals Project) Series 1984A
and 1984B. The bonds mature on March 15, 2006. The bonds are backed by two
letters of credit issued by KBC Bank N.V. On March 19, 2002, an Amended and
Restated Letter of Credit Reimbursement Agreement relating to the letters of
credit in the amount of $45.5 million was entered into by IMT and KBC Bank. In
connection with that agreement, we agreed to guarantee the obligations of IMT in
proportion to our ownership interest. Our obligation is approximately $30.3
million for principal, plus interest and other fees.
Cortez Pipeline Company Debt
Pursuant to a certain Throughput and Deficiency Agreement, the owners of
Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% owner; a
subsidiary of Exxon Mobil Corporation - 37% owner; and Cortez Vickers Pipeline
Company - 13% owner) are required, on a percentage ownership basis, to
contribute capital to Cortez Pipeline Company in the event of a cash deficiency.
The Throughput and Deficiency Agreement contractually supports the borrowings of
Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline
Company, by obligating the owners of Cortez Pipeline Company to fund cash
deficiencies at Cortez Pipeline Company, including cash deficiencies relating to
the repayment of principal and interest on borrowings by Cortez Capital
Corporation. Parent companies of the respective Cortez Pipeline Company owners
further severally guarantee, on a percentage basis, the obligations of the
Cortez Pipeline Company owners under the Throughput and Deficiency Agreement.
Due to our indirect ownership of Cortez Pipeline Company through Kinder
Morgan CO2 Company, L.P., we severally guarantee 50% of the debt of Cortez
Capital Corporation. Shell Oil Company shares our guaranty obligations jointly
and severally through December 31, 2006 for Cortez Capital Corporation's debt
programs in place as of April 1, 2000.
27
At September 30, 2002, the debt facilities of Cortez Capital Corporation
consisted of:
o a $175 million committed revolving credit facility due December 26, 2002;
o $115.7 million of Series D notes due May 15, 2013; and
o a $175 million short-term commercial paper program.
At September 30, 2002, Cortez Capital Corporation had $141.5 million of
commercial paper outstanding with an interest rate of 1.825%, the average
interest rate on the series D notes was 6.9322% and there were no borrowings
under the credit facility.
8. Partners' Capital
At September 30, 2002, our partners' capital consisted of 129,936,018 common
units, 5,313,400 class B units and 44,716,390 i-units. Together, these
179,965,808 units represent the limited partners' interest and an effective 98%
economic interest in the Partnership, exclusive of our general partner's
incentive distribution. Our common unit total consisted of 116,980,283 units
held by third parties, 11,231,735 units held by KMI and its consolidated
affiliates (excluding our general partner) and 1,724,000 units held by our
general partner. Our class B units were held entirely by Kinder Morgan, Inc. and
our i-units were held entirely by Kinder Morgan Management, LLC. Our general
partner has an effective 2% interest in the Partnership, excluding the general
partner's incentive distribution.
At December 31, 2001, our Partners' capital consisted of 129,855,018 common
units, 5,313,400 class B units and 30,636,363 i-units. Our total common units
outstanding consisted of 110,071,392 units held by third parties, 18,059,626
units held by Kinder Morgan, Inc. and its consolidated affiliates (excluding our
general partner) and 1,724,000 units held by our general partner. Our class B
units were held entirely by Kinder Morgan, Inc. and our i-units were held
entirely by Kinder Morgan Management, LLC.
Our class B units were issued in December 2000. The class B units are
similar to our common units except that they are not eligible for trading on the
New York Stock Exchange. We initially issued 29,750,000 i-units in May 2001. The
i-units are a separate class of limited partner interests in us. All of our
i-units are owned by Kinder Morgan Management, LLC and are not publicly traded.
In accordance with its limited liability company agreement, Kinder Morgan
Management's activities are restricted to being a limited partner in, and
controlling and managing the business and affairs of, the Partnership, our
operating partnerships and our subsidiaries.
On August 6, 2002, Kinder Morgan Management, LLC issued in a public
offering, an additional 12,478,900 of its shares, including 478,900 shares upon
exercise by the underwriters of an over-allotment option, at a price of $27.50
per share, less commissions and underwriting expenses. The net proceeds from the
offering were used to buy additional i-units from us. After commissions and
underwriting expenses, we received net proceeds of approximately $331.2 million
for the issuance of 12,478,900 i-units. We used the proceeds from the i-unit
issuance to reduce the debt we incurred in our acquisition of Kinder Morgan
Tejas during the first quarter of 2002.
Through the combined effect of the provisions in our partnership agreement
and the provisions of Kinder Morgan Management, LLC's limited liability company
agreement, the number of outstanding Kinder Morgan Management, LLC shares and
the number of i-units will at all times be equal. Furthermore, under the terms
of our partnership agreement, we agreed that we will not, except in liquidation,
make a distribution on an i-unit other than in additional i-units or a security
that has in all material respects the same rights and privileges as our i-units.
The number of i-units we distribute to Kinder Morgan Management, LLC is based
upon the amount of cash we distribute to the owners of our common units.
When cash is paid to the holders of our common units, we will issue additional
i-units to Kinder Morgan Management, LLC. The fraction of an i-unit paid per
i-unit owned by Kinder Morgan Management, LLC will have the same value as the
cash payment on the common unit. Based on the preceding, Kinder Morgan
Management, LLC received a distribution of 619,585 i-units on August 14, 2002.
These additional i-units distributed were based on the $0.61 per unit
distributed to our common unitholders on that date.
For the purposes of maintaining partner capital accounts, our partnership
agreement specifies that items of income and loss shall be allocated among the
partners in accordance with their percentage interests. Normal allocations
according to percentage interests are made, however, only after giving effect to
any priority income allocations in an amount equal to the incentive
distributions that are allocated 100% to our general partner. Incentive
distributions are generally defined as all cash distributions paid to our
general partner that are in excess of 2% of the aggregate value of cash and
i-units being distributed.
28
Incentive distributions allocated to our general partner are determined by
the amount that quarterly distributions to unitholders exceed certain specified
target levels. Our distribution of $0.61 per unit paid on August 14, 2002 for
the second quarter of 2002 required an incentive distribution to our general
partner of $64.4 million. Our distribution of $0.525 per unit paid on August 14,
2001 for the second quarter of 2001 required an incentive distribution to our
general partner of $50.1 million. The increased incentive distribution to our
general partner paid for the second quarter of 2002 over the distribution paid
for the second quarter of 2001 reflects the increase in the amount distributed
per unit as well as the issuance of additional units.
Our declared distribution for the third quarter of 2002 of $0.61 per unit
will result in an incentive distribution to our general partner of $69.5
million. This compares to our distribution of $0.55 per unit and incentive
distribution to our general partner of $54.2 million for the third quarter of
2001.
9. Comprehensive Income
Statement of Financial Accounting Standards No. 130, "Accounting for
Comprehensive Income", requires that enterprises report a total for
comprehensive income. For each of the nine months ended September 30, 2002 and
2001, the only difference between our net income and our comprehensive income
was the unrealized gain or loss on derivatives utilized for hedging purposes.
For more information on our hedging activities, see Note 10. Our total
comprehensive income is as follows (in thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
2002 2001 2002 2001
-------- -------- -------- --------
Net income $158,180 $115,792 $444,130 $321,685
Cumulative effect transition
adjustment -- -- -- (22,797)
Change in fair value of derivatives
used for hedging purposes (15,680) 57,592 (97,536) 20,585
Reclassification of change in fair
value of derivatives to net income 3,4422 15,390 9,386) 69,364
--------- -------- --------- ---------
Comprehensive income $145,942 $188,774 $337,208 $388,837
========= ======== ========= =========
10. Risk Management
Hedging Activities
Effective January 1, 2001, we adopted Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" as amended by Statement of Financial Accounting Standards No. 137,
"Accounting for Derivative Instruments and Hedging Activities - Deferral of the
Effective Date of FASB Statement No.133" and No. 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities". SFAS No. 133 established
accounting and reporting standards requiring that every derivative financial
instrument (including certain derivative instruments embedded in other
contracts) be recorded in the balance sheet as either an asset or liability
measured at its fair value. SFAS No. 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. If the derivatives meet those criteria, SFAS
No. 133 allows a derivative's gains and losses to offset related results on the
hedged item in the income statement, and requires that a company formally
designate a derivative as a hedge and document and assess the effectiveness of
derivatives associated with transactions that receive hedge accounting.
Our normal business activities expose us to risks associated with changes
in the market price of natural gas, natural gas liquids, crude oil and carbon
dioxide. Through Kinder Morgan, Inc., we use energy financial instruments to
reduce our risk of changes in the prices of natural gas, natural gas liquids and
crude oil markets. Our risk management activities are only used in order to
protect our profit margins and our risk management policies prohibit us from
engaging in speculative trading. Commodity-related activities of our risk
management group are monitored by our Risk Management Committee, which is
charged with the review and enforcement of our management's risk management
policy.
The fair value of these risk management instruments reflects the estimated
amounts that we would receive or pay to terminate the contracts at the reporting
date, thereby taking into account the current unrealized gains or losses on open
contracts. We have available market quotes for substantially all of the
financial instruments that we use. Our Form 10-K for the year ended December 31,
2001 contains additional information about the risks we face and the hedging
program we employ to mitigate those risks.
29
We recognized an insignificant loss during the third quarter of 2002 as a
result of ineffectiveness of these hedges. For the third quarter of 2001,
approximately $0.3 million was recognized as a loss as a result of
ineffectiveness of these hedges. Approximately $0.5 million was recognized as a
gain during the first nine months of 2002 as a result of ineffectiveness of
these hedges, and for the first nine months of 2001, approximately $0.5 million
was recognized as a loss as a result of ineffectiveness of these hedges. For all
periods presented, all gains and losses were reported within the caption
Operations and maintenance in the accompanying Consolidated Statements of
Income. For each of the nine months ended September 30, 2002 and 2001, there was
no component of the derivative instruments' gain or loss excluded from the
assessment of hedge effectiveness.
The gains and losses included in Accumulated other comprehensive income
will be reclassified into earnings as the hedged sales and purchases take place.
Approximately $37.3 million of the Accumulated other comprehensive loss balance
of $43.1 million representing unrecognized net losses on derivative activities
at September 30, 2002 is expected to be reclassified into earnings during the
next twelve months. During the nine months ended September 30, 2002, no gains or
losses were reclassified into earnings as a result of the discontinuance of cash
flow hedges due to a determination that the forecasted transactions will no
longer occur by the end of the originally specified time period.
The differences between the current market value and the original physical
contracts value associated with hedging activities are primarily reflected as
Other current assets and Accrued other current liabilities in the accompanying
consolidated balance sheets. At September 30, 2002, our balance of $62.7 million
of Other current assets included approximately $45.5 million related to risk
management hedging activities, and our balance of $209.6 million of Accrued
other current liabilities included approximately $83.9 million related to risk
management hedging activities. At December 31, 2001, our balance of $194.9
million of Other current assets included approximately $163.7 million related to
risk management hedging activities, and our balance of $209.9 million of Accrued
other current liabilities included approximately $117.8 million related to risk
management hedging activities.
At September 30, 2002, our balance of $241.2 million of Deferred charges
and other assets included approximately $9.2 million related to risk management
hedging activities, and our balance of $226.5 million of Other long-term
liabilities and deferred credits included approximately $15.1 million related to
risk management hedging activities. At December 31, 2001, our balance of $75.0
million of Deferred charges and other assets included approximately $22.0
million related to risk management hedging activities, and our balance of $246.5
million of Other long-term liabilities and deferred credits included
approximately $4.7 million related to risk management hedging activities.
While we enter into derivative transactions only with investment grade
counterparties and actively monitor their credit ratings, it is nevertheless
possible that from time to time losses will result from counterparty credit
risk.
Interest Rate Swaps
In order to maintain a cost effective capital structure, it is our policy
to borrow funds using a mix of fixed rate debt and variable rate debt. As of
September 30, 2002, we have entered into interest rate swap agreements with a
notional principal amount of $1.95 billion for the purpose of hedging the
interest rate risk associated with our fixed and floating rate debt obligations.
A notional principal amount of $1.75 billion of these agreements
effectively converts the interest expense associated with the following series
of our senior notes from fixed rates to variable rates based on an interest rate
of LIBOR plus a spread:
o $200 million principal amount of our 8.0% senior notes due March 15,
2005;
o $200 million principal amount of our 5.35% senior notes due August 15,
2007;
o $250 million principal amount of our 6.30% senior notes due February 1,
2009;
o $200 million principal amount of our 7.125% senior notes due March 15,
2012;
o $300 million principal amount of our 7.40% senior notes due March 15,
2031;
o $200 million principal amount of our 7.75% senior notes due March 15,
2032; and
o $400 million principal amount of our 7.30% senior notes due August 15,
2033.
The swap agreements for our senior notes have termination dates that
correspond to the maturity dates of such series. The swap agreements for our
7.40% senior notes contain mutual cash-out provisions at the then-current
economic value every seven years. The swap agreements for our 7.125% senior
notes contain cash-out provisions at the then-current economic value at March
15, 2009. The swap agreements for our 7.75% senior notes and our
30
7.30% senior notes contain mutual cash-out provisions at the then-current
economic value every five years. As of December 31, 2001, we were party to
interest rate swap agreements with a total notional principal amount of $900
million.
We also maintain swap agreements that effectively convert the interest
expense associated with $200 million of our floating rate debt to fixed rate.
The maturity dates of these swap agreements range from September 2, 2003 to
August 1, 2005.
These interest rate swaps have been designated as fair value hedges as
defined by SFAS No. 133. These swaps also meet the conditions required to assume
no ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them
using the "shortcut" method prescribed for fair value hedges by SFAS No. 133.
Accordingly, we adjust the carrying value of each swap to its fair value each
quarter, with an offsetting entry to adjust the carrying value of the debt
securities whose fair value is being hedged. We record interest expense equal to
the variable rate payments or fixed rate payments under the swaps. Interest
expense is accrued monthly and paid semi-annually. At September 30, 2002, we
recognized an asset of $157.5 million for the net fair value of our swap
agreements and we included this amount with Deferred charges and other assets on
the accompanying balance sheet. At December 31, 2001, we recognized a liability
of $5.4 million for the net fair value of our swap agreements and we included
this amount with Other Long-Term Liabilities and Deferred Credits on the
accompanying balance sheet. We are exposed to credit related losses in the event
of nonperformance by counterparties to these interest rate swap agreements.
While we enter into derivative transactions only with investment grade
counterparties and actively monitor their credit ratings, it is nevertheless
possible that from time to time losses will result from counterparty credit
risk.
11. Reportable Segments
We divide our operations into four reportable business segments:
o Products Pipelines;
o Natural Gas Pipelines;
o CO2 Pipelines; and
o Terminals.
We evaluate performance based on each segment's earnings, which exclude
general and administrative expenses, third-party debt costs, interest income and
expense and minority interest. Our reportable segments are strategic business
units that offer different products and services. Each segment is managed
separately because each segment involves different products and marketing
strategies.
Our Products Pipelines segment derives its revenues primarily from the
transportation of refined petroleum products, including gasoline, diesel fuel,
jet fuel and natural gas liquids. Our Natural Gas Pipelines segment derives its
revenues primarily from the gathering, transmission and storage of natural gas.
Our CO2 Pipelines segment derives its revenues primarily from the marketing and
transportation of carbon dioxide used as a flooding medium for recovering crude
oil from mature oil fields and from the production of crude oil from fields in
the Permian Basin of West Texas. Our Terminals segment derives its revenues
primarily from the transloading and storing of refined petroleum products and
dry and liquid bulk products, including coal, petroleum coke, cement, alumina,
salt, and chemicals.
Financial information by segment follows (in thousands):
Three Months Ended September 30, Nine Months Ended September 30,
2002 2001 2002 2001
-------- -------- -------- --------
Revenues
Products Pipelines $146,277 $ 137,828 $ 426,736 $ 465,702
Natural Gas Pipelines 829,614 382,656 2,168,117 1,588,165
CO2 Pipelines 38,191 29,145 104,731 90,390
Terminals 107,238 88,915 315,737 258,687
----------- --------- ---------- ----------
Total consolidated revenues $ 1,121,320 $ 638,544 $3,015,321 $2,402,944
=========== ========= ========== ==========
31
Three Months Ended September 30, Nine Months Ended September 30,
2002 2001 2002 2001
-------- -------- -------- --------
Operating income
Products Pipelines $ 86,583 $ 76,078 $ 253,223 $ 225,337
Natural Gas Pipelines 65,855 41,478 182,761 121,716
CO2 Pipelines 17,914 13,601 44,400 44,636
Terminals 46,527 38,536 134,440 106,586
----------- --------- ---------- ----------
Total segment operating
income 216,879 169,693 614,824 498,275
Corporate administrative
expenses (27,476) (24,801) (87,218) (76,436)
------------ ---------- ---------- ----------
Total consolidated
operating income $ 189,403 $ 144,892 $ 527,606 $ 421,839
============ ========== ========== ===========
Earnings from equity investments, net of amortization of excess costs
Products Pipelines $ 7,773 $ 5,800 $ 23,239 $ 16,981
Natural Gas Pipelines 5,621 5,295 17,580 15,745
CO2 Pipelines 8,021 7,551 25,423 23,764
Terminals 9 -- (38)
------------ ---------- ----------- ------------
Consolidated equity
earnings, net of
amortization $ 21,424 $ 18,646 $ 66,204 $ 56,490
============ ========== ========== ===========
Income taxes and Other, net - income (expense)
Products Pipelines $ (2,675) $ (2,166) $ (8,430) $ (6,814)
Natural Gas Pipelines (1) 15 18 18
CO2 Pipelines 6 53 96 146
Terminals (1,217) (2,313) (4,670) (5,942)
------------ ---------- ----------- ------------
Total consolidated income
taxes and Other, net $ (3,887) $ (4,411) $ (12,986) $ (12,592)
============ ========== ========== ===========
Segment earnings
Products Pipelines $ 91,681 $ 79,712 $ 268,032 $ 235,504
Natural Gas Pipelines 71,475 46,788 200,359 137,479
CO2 Pipelines 25,941 21,205 69,919 68,546
Terminals 45,319 36,223 129,732 100,644
------------ ---------- ----------- ------------
Total segment earnings 234,416 183,928 668,042 542,173
Interest and corporate
administrative
expenses (a) (76,236) (68,136) (223,912) (220,488)
------------ ---------- ----------- ------------
Total consolidated net
income $ 158,180 $ 115,792 $ 444,130 $ 321,685
============ ========== ========== ===========
(a) Includes interest and debt expense, general and administrative expenses, minority interest expense, and other
insignificant items.
Sept. 30, Dec. 31,
2002 2001
-------------- --------------
Assets
Products Pipelines $ 3,107,709 $ 3,095,899
Natural Gas Pipelines 3,027,467 2,058,836
CO2 Pipelines 572,052 503,565
Terminals 1,079,744 990,760
-------------- --------------
Total segment assets 7,786,972 6,649,060
Corporate assets (a) 318,613 83,606
-------------- --------------
Total consolidated assets $ 8,105,585 $ 6,732,666
============== ==============
(a)Includes cash, cash equivalents and certain unallocable deferred charges.
12. New Accounting Pronouncements
Statement of Financial Accounting Standards No. 143, "Accounting for Asset
Retirement Obligations", issued in July 2001 by the Financial Accounting
Standards Board, requires companies to record a liability relating to the
retirement and removal of assets used in their business. The liability is
initially recorded at its fair value, and the relative asset value is increased
by the same amount. Over the life of the asset, the liability will be accreted
to its future value and eventually extinguished when the asset is taken out of
service. The provisions of this statement are effective for fiscal years
beginning after June 15, 2002. We have not yet quantified the impacts of
adopting this Statement on our financial position or results of operations.
In April 2002, the Financial Accounting Standards Board issued SFAS No. 145,
"Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement
No. 13, and Technical Corrections." This Statement eliminates the current
requirement that gains and losses on debt extinguishment must be classified as
extraordinary items in the income statement. Instead, such gains and losses will
be classified as extraordinary items only if they are deemed to be unusual and
infrequent, in accordance with the current GAAP criteria for extraordinary
classification. In addition, SFAS No. 145 eliminates an inconsistency in lease
accounting by requiring that
32
modifications of capital leases that result in reclassification as operating
leases be accounted for consistent with sale-leaseback accounting rules. This
Statement also contains other nonsubstantive corrections to authoritative
accounting literature. The changes related to debt extinguishment will be
effective for fiscal years beginning after May 15, 2002, and the changes related
to lease accounting will be effective for transactions occurring after May 15,
2002. Adoption of this Statement will not have any immediate effect on our
consolidated financial statements. We will apply this guidance prospectively.
In June 2002, the Financial Accounting Standards Board issued SFAS No. 146,
"Accounting for Costs Associated with Exit or Disposal Activities," which
addresses accounting for restructuring and similar costs. SFAS No. 146
supersedes previous accounting guidance, principally Emerging Issues Task
Force Issue No. 94-3. We will adopt the provisions of SFAS No. 146 for
restructuring activities initiated after December 31, 2002. SFAS No. 146
requires that the liability for costs associated with an exit or disposal
activity be recognized when the liability is incurred. Under EITF No. 94-3,
a liability for an exit cost was recognized at the date of the company's
commitment to an exit plan. SFAS No. 146 also establishes that the liability
should initially be measured and recorded at fair value. Accordingly, SFAS
No. 146 may affect the timing of recognizing future restructuring costs as
well as the amounts recognized.
33
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
Results of Operations
Third Quarter 2002 Compared With Third Quarter 2001
For the quarter ended September 30, 2002, our operating results represented
the most profitable quarter in the history of the Partnership. Total
consolidated net income for the quarter was a record $158.2 million ($0.50 per
diluted unit), a 37% increase from the $115.8 million ($0.37 per diluted unit)
in net income reported for the third quarter of 2001. Revenues for the third
quarter of 2002 were a record $1,121.3 million, compared with revenues of $638.5
million in the same year-earlier period. Third quarter 2002 operating income was
a record $189.4 million, compared with $144.9 million in the third quarter of
2001. Operating expenses, consisting of our combined cost of sales, fuel, power
and operating and maintenance expenses, were $847.3 million in the third quarter
of 2002, compared with $422.0 million in the same period a year ago. Operating
income for the three months ended September 30, 2002, was $189.4 million, an
increase of 31% compared with the $144.9 million in operating income reported in
the same period last year.
Our third quarter results demonstrate balanced growth across our business
portfolio as all four of our business segments reported quarter-to-quarter
increases in earnings, operating income and revenues. The increases were driven
by volume growth from most of our assets, by the acquisitions of pipeline and
terminal businesses that we made since the end of the third quarter of 2001 and
by the expansion and capital improvement projects we have completed. The largest
of these was the January 31, 2002 purchase of Kinder Morgan Tejas. Kinder Morgan
Tejas' operations include a 3,400-mile intrastate natural gas pipeline system
that has good access to natural gas supply basins and provides a strategic,
complementary fit with our other natural gas pipeline assets in Texas,
particularly Kinder Morgan Texas Pipeline.
Third quarter earnings from equity investments, net of amortization of
excess costs, were $21.4 million in 2002 versus $18.6 million in 2001. In
addition, on October 16, 2002, we declared, for the second consecutive quarter,
a record cash distribution of $0.61 per unit (an annualized rate of $2.44). This
third quarter 2002 distribution is up 11% from the $0.55 per unit distribution
made for the third quarter of 2001.
Products Pipelines
Our Products Pipelines segment reported earnings of $91.7 million on
revenues of $146.3 million in the third quarter of 2002. In the third quarter of
2001, the segment reported earnings of $79.7 million on revenues of $137.8
million. Of the $12 million (15%) increase in quarter-to-quarter earnings, $11.1
million was associated with internal growth including higher earnings from our
CALNEV pipeline, our Pacific operations, our 44.8% ownership interest in the
Cochin Pipeline System and higher net equity earnings from our 51% ownership
interest in Plantation Pipe Line Company. The remaining $0.9 million increase in
segment earnings was associated with the acquisition of our additional 10%
ownership interest in Cochin, effective December 31, 2001.
CALNEV's earnings were up $3.2 million for the quarter, primarily due to
lower fuel and power costs and slightly higher delivery volumes. Our Pacific
operations reported a $2.8 million increase in earnings and a $4.1 million
increase in revenues, mainly driven by both a 3% increase in average tariff
rates and a 2% increase in mainline delivery volumes. Revenues and earnings from
our proportionate ownership of the Cochin Pipeline system increased $1.9 million
and $1.5 million, respectively, in the third quarter of 2002, when compared to
the same quarter last year. Most of the increases were due to higher volumes and
tariffs, however, a small portion ($0.9 million) of the earnings increase was
the result of the additional 10% ownership interest we purchased effective
December 31, 2001.
The aggregate refined petroleum products delivery volumes on all of the
segment's pipelines combined increased 2% in the third quarter of 2002 compared
to the third quarter of 2001. Gasoline deliveries alone were up 4%, and jet fuel
deliveries have continued to improve in each successive quarter of 2002 and are
beginning to return to their pre-September 11, 2001 levels.
Combined operating expenses for our Products Pipelines segment were $38.4
million in the third quarter of 2002 versus $41.1 million in the third quarter
of 2001. The $2.7 million decrease (7%) was primarily due to significantly lower
fuel and power expenses on our entire West Coast operations, most notably
Pacific, CALNEV and our West Coast product terminal businesses. In addition,
segment amortization expenses were lower in the third quarter of 2002 compared
to the third quarter of 2001 by $1.6 million, due to the cessation of goodwill
amortization beginning on January 1, 2002.
34
Earnings from our Products Pipelines' equity investments, net of
amortization of excess costs, were $7.8 million in the third quarter of 2002
versus $5.8 million in the same quarter of 2001. The $2.0 million increase (34%)
was mainly related to higher equity earnings from our 51% ownership interest in
Plantation Pipe Line Company. Although Plantation's third quarter delivery
volumes did not match the record-setting level reached in the second quarter of
2002, its volumes were almost 4% higher than last year's third quarter delivery
volumes, and its operating results continued to show strong demand for refined
petroleum products throughout the southeastern United States.
Natural Gas Pipelines
Our Natural Gas Pipelines segment reported earnings of $71.5 million on
revenues of $829.6 million in the third quarter of 2002. In the third quarter of
2001, the segment reported earnings of $46.8 million on revenues of $382.7
million. The segment's operating expenses totaled $747.9 million in the third
quarter of 2002 and $330.5 million in the third quarter of 2001. All of the
amounts for the third quarter of 2002 include the results of Kinder Morgan
Tejas, which we purchased on January 31, 2002.
Since our acquisition of Kinder Morgan Tejas, we have closely integrated our
Texas intrastate natural gas pipeline operations, taking advantage of the mutual
business being carried on by our Kinder Morgan Tejas and Kinder Morgan Texas
Pipeline systems. Combined, these businesses accounted for a $13.6 million
increase in segment earnings and a $448.2 million increase in segment revenues,
when compared to last year's third quarter.
In addition, Trailblazer Pipeline Company reported a $10.5 million increase
in quarter-to-quarter revenues and a $12.3 million increase in
quarter-to-quarter earnings. The increases resulted from higher contract demand
volumes on the recently expanded pipeline and from higher gas imbalance
recoveries. Offsetting the overall increases in segment earnings and revenues
was a $1.6 million decrease in earnings from Kinder Morgan Interstate Gas
Transmission, primarily due to higher fuel costs, and a $12.4 million decrease
in revenues earned by our Casper and Douglas natural gas gathering and
processing systems. The revenue decrease was primarily related to a decline in
gas prices in and around the Rocky Mountain region since the end of the third
quarter of 2001. However, the revenue decrease had little impact on Casper and
Douglas' earnings due to declines in costs, discussed below.
The segment's $417.4 million increase in combined operating expenses in the
third quarter of 2002 compared to the third quarter of 2001 included a $430.0
million increase from intrastate gas operations. The increase resulted from our
acquisition of Kinder Morgan Tejas as well as increases in gas volumes purchased
and a rise in the costs of purchased natural gas for both Kinder Morgan Texas
Pipeline and Kinder Morgan Tejas. Offsetting the segment's overall increase in
operating expenses, Casper and Douglas reported a $12.4 million decrease in
operating expenses. The decrease was mostly due to the lower gas prices' effects
on its gas gathering and processing operations.
Earnings from our Natural Gas Pipelines' equity investments, net of
amortization of excess costs, were essentially flat for the quarter. The segment
reported $5.6 million in net equity earnings for the third quarter of 2002
versus $5.3 million for the same prior year period. The slight $0.3 million
increase in equity earnings was mainly due to higher earnings from the segment's
50% ownership interest in Coyote Gas Treating, LLC.
CO2 Pipelines
Our CO2 Pipelines segment reported a $4.7 million (22%) increase in earnings
in the third quarter of 2002, when compared to the third quarter of 2001. For
the quarter ended September 30, 2002, CO2 Pipelines earned $25.9 million on
revenues of $38.2 million. Combined operating expenses totaled $10.6 million for
the current quarter. For the third quarter last year, our CO2 Pipelines segment
reported earnings of $21.2 million, revenues of $29.1 million and combined
operating expenses of $9.2 million. The period-to-period increases were
primarily driven by increases in oil production volumes from the SACROC Unit and
increases in carbon dioxide delivery volumes, partially offset by lower pricing
on carbon dioxide sales and lower prices resulting from our long-term hedging
program. The overall increase in segment earnings was partially offset by higher
depreciation, depletion and amortization charges. Non-cash depreciation charges
were up $2.8 million, mainly as a result of higher production volumes and
additional capital investments. In April 2002, we announced a $160 million
capital investment project consisting of a new carbon dioxide pipeline and
additional infrastructure to support our carbon dioxide flooding program at the
SACROC Unit. We anticipate beginning construction on the pipeline during the
fourth quarter of 2002, and the estimated completion date is mid-2003.
In the third quarter of 2002, our CO2 Pipelines segment reported $8.0
million in equity earnings, net of amortization of excess costs. The amount
represents a 5% increase from the $7.6 million in equity earnings in the third
quarter of 2001. The increase resulted from higher earnings from the segment's
50% ownership interest in
35
Cortez Pipeline Company mainly due to lower average debt balances and lower
average borrowing rates, partially offset by lower carbon dioxide delivery
volumes. Higher overall segment earnings were also offset slightly by a $0.5
million increase in taxes, other than income taxes, primarily the result of
higher production taxes.
Terminals
Our Terminals segment, including both our bulk and liquids terminal
businesses, reported earnings of $45.3 million, revenues of $107.2 million and
operating expenses of $50.4 million in the third quarter of 2002. This compares
to earnings of $36.2 million, revenues of $88.9 million and operating expenses
of $41.3 million in the third quarter of 2001. A significant portion of the
increases in our Terminals' operating results was due to key acquisitions we
have made since the third quarter of 2001, including:
o the terminal businesses we acquired from The Boswell Oil Company,
effective August 31, 2001;
o the terminal businesses we acquired from an affiliate of Stolt-Nielsen,
Inc. in November 2001;
o Laser Materials Services LLC, acquired effective January 1, 2002;
o a 66 2/3% interest in International Marine Terminals Partnership - a 33
1/3% interest acquired effective January 1, 2002 and an additional 33
1/3% interest acquired effective February 1, 2002;
o the Milwaukee bagging operations, acquired effective May 1, 2002; and
o the Owensboro Gateway Terminal, acquired effective September 1, 2002.
Due to the acquisitions of these businesses, our third quarter 2002 results
include an additional $18.6 million in revenues, $11.2 million in combined
operating expenses and $6.0 million in segment earnings. The remaining $3.1
million period-to-period increase in segment earnings was driven primarily by
internal growth at our liquids terminals. The increase in revenues was slightly
offset by a $0.3 million period-to-period decrease primarily related to lower
engineering services.
Excluding acquisitions, liquids terminals saw revenues increase $3.4 million
(8%) and earnings increase $2.0 million (9%) in the third quarter of 2002, when
compared to last year's third quarter. This increase was primarily due to a 5%
increase in lease tank capacity as well as increased utilization and throughput
on our existing assets in Houston, Texas and Carteret, New Jersey. Although
quarter-to-quarter revenues from all bulk terminal operations owned during both
quarters were down in 2002, primarily due to a drop in engineering services and
lower bulk tonnage volumes, earnings were higher. The increase in earnings
resulted from lower operating expenses due to the decreased volumes, and lower
income tax expenses as a result of favorable tax planning.
Segment Operating Statistics
Operating statistics for the third quarter of 2002 and 2001 are as follows:
Three Months Ended
Sept. 30, 2002 Sept. 30, 2001
-------------- --------------
Products Pipelines
Gasoline 120.7 115.9
Diesel 39.4 40.3
Jet Fuel 29.3 29.4
------- -------
Total Refined Product Volumes (MBbl) 189.4 185.6
Natural gas liquids 10.6 10.0
------- -------
Total Delivery Volumes (MBbl) (1) 200.0 195.6
Natural Gas Pipelines
Transport Volumes (Bcf) (2) 306.4 263.5
CO2 Pipelines
Delivery Volumes (Bcf) (3) 103.7 88.3
SACROC Oil Production (MMBbl) 1.2 0.8
Terminals
Bulk Terminals
Transload Tonnage (MMtons) (4) 14.2 15.8
Liquids Terminals
Leaseable Capacity (MMBbl) 35.0 33.4
Utilization % 97% 95%
36
Note: Historical pro forma for acquired assets.
(1) Includes Pacific, Plantation, North System, CALNEV, Central Florida,
Cypress and Heartland pipeline volumes.
(2) Includes Kinder Morgan Interstate Gas Transmission, Kinder Morgan Texas
Pipeline, Kinder Morgan Tejas and Trailblazer pipeline volumes.
(3) Includes Cortez, Central Basin and Canyon Reef Carriers pipeline
volumes.
(4) Includes Cora, Grand Rivers and Kinder Morgan Bulk Terminals aggregate
terminal throughputs.
Other
Items not attributable to any segment include general and administrative
expenses, interest income and expense and minority interest. Together, these
items totaled $76.2 million in the third quarter of 2002 and $68.1 million in
the third quarter of 2001. Our general and administrative expenses totaled $27.5
million in the third quarter of 2002 compared with $24.8 million in the third
quarter of 2001. The quarter-to-quarter increase in general and administrative
expenses primarily relates to additional employee benefit accruals made in
September 2002. Our total interest expense, net of interest income, was $46.4
million in the third quarter of 2002 and $41.0 million in the third quarter of
2001. The $5.4 million increase (13%) in net interest charges was due to higher
average borrowings during the third quarter of 2002 compared with the same
period in 2001, partially offset by lower average interest rates during the
third quarter of 2002.
Nine Months Ended September 30, 2002 Compared With Nine Months Ended
September 30, 2001
Net income for the nine months ended September 30, 2002 was $444.1 million
($1.46 per diluted unit) compared with net income of $321.7 million ($1.16 per
diluted unit) in the first nine months of 2001. The 38% increase in earnings for
the comparable January through September nine-month periods is in line with the
37% increase in earnings for the comparable third quarter periods. We reported
total revenues of $3,015.3 million for the first nine months of 2002, compared
with $2,402.9 million for the first nine months of 2001. Our operating expenses
for the nine-month period ended September 30, 2002, were $2,233.2 million, and
for the nine-month period ended September 30, 2001, were $1,767.7 million.
Operating income for the nine months ended September 30, 2002, was $527.6
million, an increase of 25% compared with the $421.8 million in operating income
reported in the same year-earlier period. Our equity earnings from investments,
less amortization of excess costs, were $66.2 million in the first nine months
of 2002 versus $56.5 million in the same period last year.
Products Pipelines
Products Pipelines reported earnings of $268.0 million on revenues of $426.7
million for the first nine months of 2002. These amounts compare with earnings
of $235.5 million on revenues of $465.7 million for the same period of 2001. The
$39.0 million (8%) decrease in period-to-period segment revenues includes a
reduction of $67.4 million in transmix revenues resulting primarily from our
long-term transmix processing agreement with Duke Energy Merchants. During the
first quarter of 2001, we entered into a 10-year agreement with Duke Energy
Merchants to process transmix on a fee basis only. Under the agreement, Duke
Energy Merchants is responsible for procurement of the transmix and sale of the
products after processing. This agreement allows us to eliminate commodity price
exposure in our transmix operations.
The overall decrease in segment revenues was partly offset by a $13.3
million increase in revenues earned by our CALNEV pipeline and by a $8.6 million
increase in revenues earned from our investment in the Cochin Pipeline System.
The increases reflect our acquisitions of CALNEV on March 30, 2001 from GATX
Corporation, and our acquisition of an additional 10% interest in Cochin
(bringing our total interest to 44.8%) effective December 31, 2001. Revenues and
earnings from Cochin also increased during the nine-month period of 2002 due to
higher volumes and tariffs. Revenues from our Pacific operations increased $6.9
million (3%), primarily as a result of a matching 3% increase in average tariff
rates.
Combined operating expenses for our Products Pipelines segment were $110.6
million in the first nine-months of 2002 versus $179.3 million in the same
period last year. The $68.7 million reduction (38%) in expenses was primarily
due to our agreement with Duke Energy Merchants, which reduced our cost of
products sold by approximately $68.6 million. Excluding cost of sales, the
segment's combined fuel, power and operating and maintenance charges were
essentially flat for the comparable nine-month periods. Lower operating and
maintenance expenses, primarily due to efficiencies achieved at our West Coast
terminals since we acquired them from GATX, were offset by higher fuel and power
expenses on our Pacific operations' pipelines.
Earnings from our Products Pipelines' equity investments, net of
amortization of excess costs, were $23.2 million in the first nine-months of
2002 versus $17.0 million in the same period of 2001. The $6.2 million increase
37
(36%) was mainly related to higher equity earnings from our 51% ownership
interest in Plantation Pipe Line Company. Plantation reported higher earnings
for the first nine months of 2002 compared to the same nine-month period of
2001. Its revenues were higher due to increased delivery volumes, its operating
expenses were lower due to lower power costs, and its interest expenses were
lower due to lower average borrowing rates.
Natural Gas Pipelines
Our Natural Gas Pipelines segment reported earnings of $200.4 million on
revenues of $2,168.1 million in the first nine months of 2002. In the same 2001
period, the segment reported earnings of $137.5 million on revenues of $1,588.2
million. The increase in revenues and earnings for the first nine months of 2002
over the previous year was primarily driven by our acquisition of Kinder Morgan
Tejas on January 31, 2002, as well as strong growth in the Trailblazer Pipeline
Company.
The $579.9 million overall increase in year-over-year segment revenues
includes $627.3 million in higher revenues from our combined Texas intrastate
systems, which buy, sell and transport natural gas primarily within the state of
Texas. Higher revenues attributed to our Tejas acquisition were partially offset
by a decrease in gas sale prices since the end of the third quarter of 2001.
Excluding Kinder Morgan Tejas and Kinder Morgan Texas Pipeline, segment
revenues decreased $47.3 million in the comparable nine-month periods. The drop
in segment revenues includes a $42.6 million decrease from our Casper and
Douglas gas gathering and processing system, primarily due to an overall drop in
gas prices since the end of the third quarter of 2001, most significantly in the
first six months of 2002. Revenues from Kinder Morgan Interstate Gas
Transmission decreased $21.2 million, primarily due to less operational gas
sales and lower fuel recovery rates in 2002. Partially offsetting this decrease
in segment revenues was a $16.5 million increase in revenues earned by the
Trailblazer Pipeline Company. Trailblazer's natural gas transport revenue
increased primarily as a result of the completed pipeline expansion project. In
May 2002, Trailblazer completed a $59 million expansion project that increased
transportation capacity on the pipeline by approximately 60%. For the first nine
months of 2002, Trailblazer's natural gas transport volumes increased 17%, when
compared to the same period a year-ago.
The segment's operating expenses totaled $1,937.9 million in the first nine
months of 2002 and $1,435.1 million in the same year-ago period. The $502.8
million increase resulted primarily from the inclusion of newly acquired Kinder
Morgan Tejas, partially offset by lower purchased gas costs. Casper and Douglas
reported a $40.8 million decrease in expenses, also primarily driven by lower
gas purchase costs. Kinder Morgan Interstate Gas Transmission reported a $11.2
million decrease in operating expenses, mostly due to lower fuel costs, less
operational gas sales and favorable gas imbalance settlements.
Earnings from our Natural Gas Pipelines' equity investments, net of
amortization of excess costs, were $17.6 million for the first nine months of
2002 versus $15.7 million for the same prior year period. The $1.9 million
increase (12%) in equity earnings was mainly due to higher earnings from the
segment's 49% interest in the Red Cedar Gathering Company.
CO2 Pipelines
Our CO2 Pipelines segment reported earnings of $69.9 million on revenues of
$104.7 million in the first nine months of 2002. The segment reported earnings
of $68.5 million on revenues of $90.4 million in the same nine-month period of
2001. Combined operating expenses totaled $33.4 million for the first nine
months of 2002 versus $27.0 million in the same period of 2001. The $14.3
million (16%) increase in segment revenues was driven by higher oil production
volumes produced at the segment's SACROC Unit. However, the segment's overall
net earnings increased only slightly, $1.4 million (2%), mainly due to the
higher production volumes, partially offset by an $8.7 million (69%) increase in
non-cash depreciation and depletion charges. Depreciation charges were up as a
result of the higher production volumes, the capital expenditures and
acquisitions made since the end of the third quarter of 2001, and a change to a
higher depreciation rate.
During the first nine months of 2002, our CO2 Pipelines reported $25.4
million in equity earnings, net of amortization of excess costs. This compares
to $23.8 million during the same period of 2001. The $1.6 million increase (7%)
was due to higher returns from the segment's equity interest in Cortez Pipeline
Company, partly offset by lower returns from its 15% equity investment in MKM
Partners, L.P., an oil and gas joint venture with Marathon Oil Company that
began January 1, 2001.
38
Terminals
Our Terminals segment reported earnings of $129.7 million, revenues of
$315.7 million and operating expenses of $151.4 million in the first nine months
of 2002. These results compare to earnings of $100.6 million, revenues of $258.7
million and operating expenses of $126.4 million in the comparable period of
2001. The increases in segment operating results were mainly the result of
terminal acquisitions we have made since the beginning of 2001 and increased
throughput at our liquids terminal facilities. Our acquisitions included the
businesses described above in our quarterly discussion and analysis, as well as
our purchase of Pinney Dock & Transport LLC, effective March 1, 2001, and our
purchase of certain bulk terminal businesses from Koninklijke Vopak N.V.,
effective July 10, 2001. Due to the inclusion of these businesses, we realized
incremental revenues of $71.5 million, operating expenses of $43.5 million and
earnings of $23.0 million in the first nine months of 2002, over the comparable
period of 2001.
Excluding engineering services, revenues from bulk terminals, coal
facilities and liquids terminals owned during both nine-month periods were
relatively flat, but combined operating expenses were down 5% compared to 2001,
mainly due to lower bulk tonnage volumes. Period-to-period bulk transload
volumes, for all bulk terminals owned at September 30, 2002, decreased 5%
compared to last year. The decline was primarily due to lower terminal transfers
of coal and salt tonnage.
At our liquids terminals, expansion projects, higher utilization rates and
higher throughput contributed to a $4.4 million increase in earnings and a $4.6
million increase in revenues. Our leaseable capacity increased by 5% and at the
same time our capacity leased increased from 95% to 97% over the same nine-month
periods. The increased capacity reflects the expansion projects and related
leases at our Carteret Terminal in New York Harbor and our Pasadena Terminal on
the Houston, Texas Ship Channel. The overall increase in segment earnings,
revenues and expenses were partially offset by a year-over-year decline in
engineering services.
Segment Operating Statistics
Operating statistics for the first nine months of 2002 and 2001 are as
follows:
Nine Months Ended
Sept. 30, 2002 Sept. 30, 2001
-------------- --------------
Products Pipelines
Gasoline 350.5 331.0
Diesel 115.6 122.6
Jet Fuel 83.9 90.7
------ ------
Total Refined Product Volumes (MBbl) 550.0 544.3
Natural gas liquids 30.4 31.7
------ ------
Total Delivery Volumes (MBbl) (1) 580.4 576.0
Natural Gas Pipelines
Transport Volumes (Bcf) (2) 808.7 728.3
CO2 Pipelines
Delivery Volumes (Bcf) (3) 326.3 280.2
SACROC Oil Production (MMBbl)
3.3 2.4
Terminals
Bulk Terminals
Transload Tonnage (MMtons) (4) 41.9 44.0
Liquids Terminals
Leaseable Capacity (MMBbl) 35.0 33.4
Utilization % 97% 95%
Note: Historical pro forma for acquired assets.
(1) Includes Pacific, Plantation, North System, CALNEV, Central Florida,
Cypress and Heartland pipeline volumes.
(2) Includes Kinder Morgan Interstate Gas Transmission, Kinder Morgan Texas
Pipeline, Kinder Morgan Tejas and Trailblazer pipeline volumes.
(3) Includes Cortez, Central Basin and Canyon Reef Carriers pipeline volumes.
(4) Includes Cora, Grand Rivers and Kinder Morgan Bulk Terminals aggregate
terminal throughputs.
Other
Items not attributable to any segment include general and administrative
expenses, interest income and expense and minority interest. General and
administrative expenses were $87.2 million for the nine-months ended September
30, 2002, and $76.4 million for the nine-months ended September 30, 2001. The
increase was mainly a
39
result of higher administrative costs and spending associated with the new
acquisitions and investments we made since September 30, 2001.
Our total interest expense, net of interest income, was $129.2 million in
the firs nine months of 2002, compared with $136.1 million in the same
year-earlier period. The $6.9 million (5%) decrease in net interest items
reflects the decrease in average borrowing rates that have occurred since
September 30, 2001. The favorable change in net financing charges was partially
offset by higher average borrowings. During the first nine months of 2002, we
issued $1.5 billion in principal amount of senior notes and we retired a
maturing amount of $200 million in principal amount of senior notes. During the
first nine months of 2001, we closed a public offering of $1.0 billion in
principal amount of senior notes.
Financial Condition
The following table illustrates the sources of our invested capital. In
addition to our results of operations, these balances are affected by our
financing activities as discussed below (dollars in thousands):
Sept. 30, 2002 Dec. 31, 2001
-------------- -------------
Long-term debt, less market value of
interest rate swaps $ 3,611,061 $ 2,237,015
Minority interest
41,927 65,236
Partners' capital
3,406,826 3,159,034
----------- -----------
Total capitalization 7,059,814 5,461,285
Short-term debt, less cash and cash
equivalents (62,380) 497,417
----------- -----------
Total invested capital $ 6,997,434 $ 5,958,702
=========== ===========
Capitalization:
- ---------------
Long-term debt, less market value of
interest rate swaps 51.1% 41.0%
Minority interest 0.6% 1.2%
Partners' capital 48.3% 57.8%
Invested Capital:
- -----------------
Total debt, less cash, cash equivalents
and market value of interest rate swaps 50.7% 45.9%
Partners' capital and minority interest 49.3% 54.1%
Our primary cash requirements, in addition to normal operating expenses, are
debt service, sustaining capital expenditures, expansion capital expenditures
and quarterly distributions to our common unitholders, class B unitholders and
general partner. In addition to utilizing cash generated from operations, we
could meet our cash requirements (other than distributions to our common
unitholders, class B unitholders and general partner) through borrowings under
our credit facilities, issuing short-term commercial paper, long-term notes or
additional common units or issuing additional i-units to Kinder Morgan
Management, LLC. In general, we expect to fund:
o cash distributions and sustaining capital expenditures with existing
cash and cash flows from operating activities;
o expansion capital expenditures and working capital deficits with cash
retained as a result of paying quarterly distributions on i-units in
additional i-units, additional borrowings, the issuance of additional
common units or the issuance of additional i-units to Kinder Morgan
Management, LLC;
o interest payments from cash flows from operating activities; and
o debt principal payments with additional borrowings as such debt
principal payments become due or by the issuance of additional common
units or the issuance of additional i-units to Kinder Morgan Management,
LLC.
As a master limited partnership, our common units are attractive primarily
to individual investors. Individual investors represent a small segment of the
total equity capital market. We believe institutional investors prefer shares of
Kinder Morgan Management, LLC over our common units due to tax and other
regulatory considerations. Thus, Kinder Morgan Management, LLC makes purchases
of i-units issued by us with the proceeds from the sale of Kinder Morgan
Management, LLC shares to institutions, which may not wish to invest in us.
At September 30, 2002, our current commitments for capital expenditures were
approximately $23.0 million. This amount has been committed primarily for the
purchase of plant and equipment and is based on the payments we
40
expect to need for our 2002 sustaining capital expenditure plan. All of our
capital expenditures, with the exception of sustaining capital expenditures, are
discretionary.
Some of our customers are experiencing severe financial problems that have
had a significant impact on their creditworthiness. We are working to implement,
to the extent allowable under applicable laws and regulations, prepayments and
other security requirements such as letters of credit to enhance our credit
position relating to amounts owed from these customers. We cannot assure that
one or more of our financially distressed customers will not default on their
obligations to us or that such a default or defaults will not have a material
adverse effect on our business.
Operating Activities
Net cash provided by operating activities was $546.3 million for the
nine-months ended September 30, 2002, versus $404.4 million in the comparable
period of 2001. The period-to-period increase of $141.9 million in cash flow
from operations resulted chiefly from a $139.0 million increase in cash earnings
from across our business portfolio. Distributions from equity investments
increased $8.1 million due to higher returns from our investments in Plantation
Pipe Line Company and Cortez Pipeline Company. Offsetting the overall increase
in cash provided by operating activities were slightly lower cash inflows
relative to net changes in working capital items, primarily due to less
favorable settlements of product inventory as a result of the transmix
processing agreement we entered into with Duke Energy Merchants in 2001.
Investing Activities
Net cash used in investing activities was $1,218.4 million for the nine
month period ended September 30, 2002, compared to $1,632.9 million in the
comparable 2001 period. The $414.5 million decrease in funds utilized in
investing activities is primarily attributable to higher expenditures made for
strategic acquisitions in the 2001 period. For the nine months ended September
30, 2002, our acquisition outlays totaled $864.3 million, including $723.2
million for Kinder Morgan Tejas and $80.1 million for the remaining 33 1/3%
ownership interest in Trailblazer Pipeline Company. For the nine months ended
September 30, 2001, our asset acquisitions totaled $1,453.2 million, including
$982.7 million used to acquire the GATX pipelines and terminal businesses and
$359.1 million used to acquire natural gas pipeline assets formerly leased and
operated by Kinder Morgan Texas Pipeline, L.P.
Offsetting the overall decline in funds used in investing activities was a
$163.8 million increase in funds used for capital expenditures in the first nine
months of 2002 compared to the same period in 2001. Including expansion and
maintenance projects, our capital expenditures were $342.6 million in the first
nine months of 2002. We spent $178.8 million for capital expenditures in the
same year-ago period. The increase was due primarily to continued investment in
our Natural Gas Pipelines, Terminals and CO2 Pipelines business segments. We
continue to expand and grow our existing businesses and have current projects in
place that will significantly add storage and throughput capacity to our
terminaling, natural gas transmission and carbon dioxide flooding operations.
Our sustaining capital expenditures were $52.3 million for the first nine months
of 2002 compared to $40.5 million for the first nine months of 2001.
Financing Activities
Net cash provided by financing activities amounted to $671.7 million for the
nine months ended September 30, 2002. The decrease of $581.8 million from the
comparable 2001 period was mainly the result of lower cash inflows from equity
financing activities. In May 2001, we received $996.9 million as proceeds from
our initial sale of 29,750,000 million i-units to Kinder Morgan Management, LLC.
In August 2002, we raised $331.2 million from our sale of an additional
12,478,900 i-units to Kinder Morgan Management, LLC.
The overall decrease in funds provided by our financing activities also
resulted from a $85.5 million increase in distributions to our partners.
Distributions to all partners increased to $426.7 million in the first nine
months of 2002 compared to $341.2 million in the same year-ago period. The
increase in distributions was due to:
o an increase in the per unit cash distributions paid;
o an increase in the number of units outstanding; and
o an increase in the general partner incentive distributions, which
resulted from both increased cash distributions per unit and an increase
in the number of common units and i-units outstanding.
The overall decrease in funds provided by financing activities was partly
offset by a $181.2 million decrease in overall debt financing activities. During
the first nine months of each of the years 2001 and 2002, we purchased the
pipeline and terminal businesses we acquired primarily with borrowings under our
commercial paper program. We then raised funds by completing public and private
debt offerings of senior notes and by issuing additional i-units. We then used
the proceeds from these debt and equity issuances to reduce our borrowings under
our commercial paper program. During the first nine months of 2002, we closed a
public offering of $750 million in principal amount of senior notes, completed a
private placement of $750 million in principal amount of senior notes to
qualified institutional buyers and retired a maturing amount of $200 million in
principal amount of senior notes. In comparison, during the first nine months of
2001, we closed a public offering of $1.0 billion in principal amount
41
of senior notes.
On August 14, 2002, we paid a quarterly distribution of $0.61 per unit for
the second quarter of 2002, 16% greater than the $0.525 distribution paid for
the second quarter of 2001. We paid this distribution in cash to our common
unitholders and to our class B unitholders. Kinder Morgan Management, LLC, our
sole i-unitholder, received additional i-units based on the $0.61 cash
distribution per common unit. For each outstanding i-unit that Kinder Morgan
Management, LLC held, a fraction of an i-unit was issued. The fraction was
determined by dividing:
o the cash amount distributed per common unit
by
o the average of Kinder Morgan Management's shares' closing market prices
for the ten consecutive trading days preceding the date on which the
shares began to trade ex-dividend under the rules of the New York Stock
Exchange.
On October 16, 2002, we declared a cash distribution for the quarterly
period ended September 30, 2002, of $0.61 per unit. The distribution will be
paid on or before November 14, 2002, to unitholders of record as of October 31,
2002. Our common unitholders and class B unitholders will receive cash. Kinder
Morgan Management, LLC, our sole i-unitholder will receive a distribution in the
form of additional i-units based on the $0.61 distribution per common unit. We
believe that future operating results will continue to support similar levels of
quarterly cash and i-unit distributions, however, no assurance can be given that
future distributions will continue at such levels.
Partnership Distributions
Our partnership agreement requires that we distribute 100% of available cash
as defined in our partnership agreement to our partners within 45 days following
the end of each calendar quarter in accordance with their respective percentage
interests. Available cash consists generally of all of our cash receipts,
including cash received by our operating partnerships, less cash disbursements
and net additions to reserves (including any reserves required under debt
instruments for future principal and interest payments) and amounts payable to
the former general partner of SFPP, L.P. in respect of its remaining 0.5%
interest in SFPP.
Our general partner is granted discretion by our partnership agreement,
which discretion has been delegated to Kinder Morgan Management, LLC, subject to
the approval of our general partner in certain cases, to establish, maintain and
adjust reserves for future operating expenses, debt service, maintenance capital
expenditures, rate refunds and distributions for the next four quarters. These
reserves are not restricted by magnitude, but only by type of future cash
requirements with which they can be associated. When Kinder Morgan Management,
LLC determines our quarterly distributions, it considers current and expected
reserve needs along with current and expected cash flows to identify the
appropriate sustainable distribution level.
Typically, our general partner and owners of our common units and class B
units receive distributions in cash, while Kinder Morgan Management, LLC, the
sole owner of our i-units, receives distributions in additional i-units. For
each outstanding i-unit, a fraction of an i-unit will be issued. The fraction is
calculated by dividing the amount of cash being distributed per common unit by
the average closing price of Kinder Morgan Management's shares over the ten
consecutive trading days preceding the date on which the shares begin to trade
ex-dividend under the rules of the New York Stock Exchange. The cash equivalent
of distributions of i-units will be treated as if it had actually been
distributed for purposes of determining the distributions to our general
partner. We will not distribute cash to i-unit owners but will retain the cash
for use in our business.
Available cash is initially distributed 98% to our limited partners and 2%
to our general partner. These distribution percentages are modified to provide
for incentive distributions to be paid to our general partner in the event that
quarterly distributions to unitholders exceed certain specified targets.
Available cash for each quarter is distributed:
o first, 98% to the owners of all classes of units pro rata and 2% to our
general partner until the owners of all classes of units have received a
total of $0.15125 per unit in cash or equivalent i-units for such
quarter;
o second, 85% of any available cash then remaining to the owners of all
classes of units pro rata and 15% to our general partner until the owners
of all classes of units have received a total of $0.17875 per unit in
cash or equivalent i-units for such quarter;
42
o third, 75% of any available cash then remaining to the owners of all
classes of units pro rata and 25% to our general partner until the owners
of all classes of units have received a total of $0.23375 per unit in
cash or equivalent i-units for such quarter; and
o fourth, 50% of any available cash then remaining to the owners of all
classes of units pro rata, to owners of common units and class B units in
cash and to owners of i-units in the equivalent number of i-units, and
50% to our general partner.
Incentive distributions are generally defined as all cash distributions paid
to our general partner that are in excess of 2% of the aggregate value of cash
and i-units being distributed. The general partner's incentive distribution for
the distribution that we declared for the third quarter of 2002 was $69.5
million. The general partner's incentive distribution for the distribution that
we declared for the third quarter of 2001 was $54.2 million. The general
partner's incentive distribution that we paid during the third quarter of 2002
to our general partner (for the second quarter of 2002) was $64.4 million. The
general partner's incentive distribution that we paid during the third quarter
of 2001 to our general partner (for the second quarter of 2001) was $50.1
million. All partnership distributions we declare for the fourth quarter of each
year are declared and paid in the first quarter of the following year.
Information Regarding Forward-Looking Statements
This filing includes forward-looking statements. These forward-looking
statements are identified as any statement that does not relate strictly to
historical or current facts. They use words such as "anticipate," "believe,"
"intend," "plan," "projection," "forecast," "strategy," "position," "continue,"
"estimate," "expect," "may," "will," or the negative of those terms or other
variations of them or comparable terminology. In particular, statements, express
or implied, concerning future operating results or the ability to generate
sales, income or cash flow are forward-looking statements. Forward-looking
statements are not guarantees of performance. They involve risks, uncertainties
and assumptions. Future actions, conditions or events and future results of our
operations may differ materially from those expressed in these forward-looking
statements. Many of the factors that will determine these results are beyond our
ability to control or predict. Specific factors which could cause actual results
to differ from those in the forward-looking statements include:
o price trends and overall demand for natural gas liquids, refined
petroleum products, oil, carbon dioxide, natural gas, coal and other bulk
materials and chemicals in the United States; economic activity, weather,
alternative energy sources, conservation and technological advances may
affect price trends and demand;
o changes in our tariff rates implemented by the Federal Energy Regulatory
Commission or the California Public Utilities Commission;
o our ability to integrate any acquired operations into our existing
operations;
o our ability to acquire new businesses and assets and to make expansions
to our facilities;
o difficulties or delays experienced by railroads, barges, trucks, ships
or pipelines in delivering products to our terminals;
o our ability to successfully identify and close acquisitions and make
cost-saving changes in operations;
o shut-downs or cutbacks at major refineries, petrochemical or chemical
plants, utilities, military bases or other businesses that use or supply
our services;
o changes in laws or regulations, third party relations and approvals,
decisions of courts, regulators and governmental bodies may adversely
affect our business or our ability to compete;
o our ability to offer and sell equity securities and debt securities or
obtain debt financing in sufficient amounts to implement that portion of
our business plan that contemplates growth through acquisitions of
operating businesses and assets and expansions of our facilities;
o our indebtedness could make us vulnerable to general adverse economic and
industry conditions, limit our ability to borrow additional funds, place
us at competitive disadvantages compared to our competitors that have
less debt or have other adverse consequences;
o interruptions of electric power supply to our facilities due to natural
disasters, power shortages, strikes, riots, terrorism, war or other
causes;
o acts of sabotage, terrorism or other similar acts causing damage greater
than our insurance coverage;
o the condition of the capital markets and equity markets in the United
States;
o the political and economic stability of the oil producing nations of the
world;
o national, international, regional and local economic, competitive and
regulatory conditions and developments;
o the ability to achieve cost savings and revenue growth;
o rates of inflation;
o interest rates;
o the pace of deregulation of retail natural gas and electricity;
43
o the timing and extent of changes in commodity prices for oil, natural
gas, electricity and certain agricultural products, and
o the timing and success of business development efforts.
You should not put undue reliance on any forward-looking statements.
See Items 1 and 2 "Business and Properties - Risk Factors" of our annual
report filed on Form 10-K for the year ended December 31, 2001, for a more
detailed description of these and other factors that may affect the
forward-looking statements. When considering forward-looking statements, one
should keep in mind the risk factors described in our 2001 Form 10-K report. The
risk factors could cause our actual results to differ materially from those
contained in any forward-looking statement.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
There have been no material changes in market risk exposures that would
affect the quantitative and qualitative disclosures presented as of December 31,
2001, in Item 7a of our 2001 Form 10-K report. For more information on our risk
management activities, see Note 10 to our consolidated financial Statements
included elsewhere in this report.
Item 4. Controls and Procedures.
Within the 90-day period prior to the filing of this report, we carried out
an evaluation under the supervision and with the participation of our
management, including our Chief Executive Officer and Chief Financial Officer,
of the effectiveness of the design and operation of our disclosure controls and
procedures pursuant to Rule 13a-14(c) under the Securities Exchange Act of 1934.
Based upon that evaluation, our Chief Executive Officer and Chief Financial
Officer concluded that the design and operation of our disclosure controls and
procedures were effective. No significant changes were made in our internal
controls or in other factors that could significantly affect these controls
subsequent to the date of their evaluation.
44
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
See Part I, Item 1, Note 3 to our consolidated financial statements entitled
"Litigation and Other Contingencies", which is incorporated herein by reference.
Item 2. Changes in Securities and Use of Proceeds.
None.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
Item 5. Other Information.
Risk Factors
Set forth below are two updated risk factors relating to our business. For
additional risk factors about us, see our Form 10-K for the year ended December
31, 2001 filed with the Securities and Exchange Commission.
PENDING FEDERAL ENERGY REGULATORY COMMISSION AND CALIFORNIA PUBLIC UTILITIES
COMMISSION PROCEEDINGS SEEK SUBSTANTIAL REFUNDS AND REDUCTIONS IN TARIFF RATES
ON SOME OF OUR PIPELINES. If the proceedings are determined adversely, they
could have a material adverse impact on us. Regulators and shippers on our
pipelines have rights to challenge the rates we charge under certain
circumstances prescribed by applicable regulations. In 1992, and from 1995
through 2001, some shippers on our pipelines filed complaints with the Federal
Energy Regulatory Commission and California Public Utilities Commission that
seek substantial refunds for alleged overcharges during the years in question
and prospective reductions in the tariffs rates on our Pacific operations'
pipeline system.
The FERC complaints, separately docketed in two different proceedings,
predominantly attacked the interstate pipeline tariff rates of our Pacific
operations' pipeline system, contending that the rates were not just and
reasonable under the Interstate Commerce Act and should not be entitled to
"grandfathered" status under the Energy Policy Act. Complaining shippers seek
substantial reparations for alleged overcharges during the years in question and
request prospective rate reductions on each of the challenged facilities.
Hearings on the second of these two proceedings began in October 2001, and an
initial decision by the administrative law judge is expected in the fourth
quarter of 2002.
The complaints filed before the CPUC challenge the rates charged for
intrastate transportation of refined petroleum products through the Pacific
operations' pipeline system in California. After the CPUC dismissed the initial
complaint and subsequently granted a limited rehearing on April 10, 2000, the
complainants filed a new complaint with the CPUC asserting the intrastate rates
were not just and reasonable.
We currently believe the FERC complaints seek approximately $197 million in
tariff reparations and prospective annual tariff reductions, the aggregate
average annual impact of which would be approximately $45 million. We currently
believe the CPUC complaints seek approximately $15 million in tariff
reparations and prospective annual tariff reductions, the aggregate average
annual impact of which would be approximately $31 million. These amounts are
the amounts we currently believe the complainants are seeking. Please see Note 3
to the accompanying financial statements for additional information regarding
these complaints. Amounts, if any, ultimately owed will be impacted by the
passage of time and the application of interest. Decisions regarding these
complaints could negatively impact our cash flow. Additional challenges to
tariff rates could be filed with the FERC and CPUC in the future.
PROPOSED RULEMAKING BY THE FEDERAL ENERGY REGULATORY COMMISSION OR OTHER
REGULATORY AGENCIES HAVING JURISDICTION COULD ADVERSELY IMPACT OUR INCOME AND
OPERATIONS. For example, on September 27, 2001, FERC issued a Notice of Proposed
Rulemaking in Docket No. RM01-10. The proposed rule would expand FERC's current
standards of conduct to include a regulated transmission provider and all of its
energy affiliates. It is not known whether FERC will issue a final rule in this
docket and, if it does, whether as a result we could incur increased costs and
increased difficulty in our operations. Generally speaking, new regulations or
different interpretations of existing
45
regulations applicable to our assets could have a negative impact on our
business, financial condition and results of operations.
THE DISTRESSED FINANCIAL CONDITION OF SOME OF OUR CUSTOMERS COULD HAVE AN
ADVERSE IMPACT ON US IN THE EVENT THESE CUSTOMERS ARE UNABLE TO PAY US FOR THE
SERVICES WE PROVIDE. Some of our customers are experiencing severe financial
problems. The bankruptcy of one or more of them, or some other similar
proceeding or liquidity constraint might make it unlikely that we would be able
to collect all or a significant portion of amounts owed by the distressed entity
or entities.
INCREASED REGULATORY REQUIREMENTS RELATING TO THE INTEGRITY OF OUR PIPELINES
WILL REQUIRE US TO SPEND ADDITIONAL MONEY TO COMPLY WITH THESE REQUIREMENTS.
Through our regulated pipeline subsidiaries, we are subject to extensive laws
and regulations related to pipeline integrity. Compliance with existing
regulations requires significant capital expenditures. Additional laws and
regulations that may be enacted in the future could significantly increase
the amount of these expenditures.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits
4.1* -- Form of Indenture dated August 19, 2002 between Kinder Morgan Energy
Partners and Wachovia Bank, National Association, as Trustee
(incorporated by reference from Exhibit 4.1 of Kinder Morgan Energy
Partners, L.P.'s Registration Statement on Form S-4 (Registration No.
333-100346) filed with the Securities and Exchange Commission
on October 4, 2002).
4.2* -- Form of First Supplemental Indenture to Indenture dated August 19,
2002, dated August 23, 2002 between Kinder Morgan Energy Partners and
Wachovia Bank, National Association, as Trustee (incorporated by
reference from Exhibit 4.2 of Kinder Morgan Energy Partners, L.P.'s
Registration Statement on Form S-4 (Registration No. 333-100346) filed
with the Securities and Exchange Commission on October 4, 2002).
4.3* -- Form of 5.35% Note and Form of 7.30% Note (contained in the Indenture
filed as Exhibit 4.1).
4.4* -- Form of Registration Rights Agreement dated August 19, 2002 among Kinder
Morgan Energy Partners, Salomon Smith Barney Inc., J.P. Morgan
Securities Inc., Wachovia Securities, Inc., RBC Dominion Securities
Corporation, SunTrust Capital Markets, Inc., Banc One Capital Markets,
Inc., and Credit Lyonnais Securities (USA) Inc. (incorporated by
reference from Exhibit 4.4 of Kinder Morgan Energy Partners, L.P.'s
Registration Statement on Form S-4 (Registration No. 333-100346) filed
with the Securities and Exchange Commission on October 4, 2002).
4.5* -- Form of Registration Rights Agreement dated August 23, 2002 between
Kinder Morgan Energy Partners and J.P. Morgan Securities Inc.
(incorporated by reference from Exhibit 4.5 of Kinder Morgan Energy
Partners, L.P.'s Registration Statement on Form S-4 (Registration No.
333-100346) filed with the Securities and Exchange Commission
on October 4, 2002).
4.6 -- Certain instruments with respect to long-term debt of the Partnership
and its consolidated subsidiaries which relate to debt that does not
exceed 10% of the total assets of the Partnership and its consolidated
subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A) of
Regulation S-K, 17 C.F.R. ss.229.601. The Partnership hereby agrees to
furnish supplementally to the Securities and Exchange Commission a copy
of each such instrument upon request.
11 -- Statement re: computation of per share earnings.
99.1 -- Chief Executive Officer Certification.
99.2 -- Chief Financial Officer Certification.
- ---------------------
* Asterisk indicates exhibits incorporated by reference as indicated; all other
exhibits are filed herewith.
(b) Reports on Form 8-K
Current report dated July 8, 2002 on Form 8-K was filed on July 8, 2002,
pursuant to Items 7 and 9 of that form. We provided notice that we expected to
exceed our consensus earnings estimate of $0.43 per unit for the second quarter
of 2002, and that we were comfortable with and expected to meet or exceed our
annual consensus earnings of $1.82 per unit. A copy of the press release was
filed as an exhibit pursuant to Item 7.
Current report dated July 23, 2002 on Form 8-K was filed on July 23, 2002,
pursuant to Items 5 and 7 of that form. We reported that a special meeting of
shareholders of Kinder Morgan Management, LLC was held on July 23, 2002, for the
purpose of considering and voting upon a proposal to eliminate the exchange
feature of Kinder Morgan Management's shares by amending its limited liability
company agreement. Approximately 90 % of those who voted approved the proposal
to eliminate the exchange feature. The amendment to Kinder Morgan Management,
LLC's limited liability company agreement eliminating the exchange feature was
effective at the close of business July 23, 2002. A copy of the press release
was filed as an exhibit pursuant to Item 7.
Current report dated August 8, 2002 on Form 8-K was filed on August 9, 2002,
pursuant to Items 7 and 9 of that form. On August 8, 2002, the Chairman and
Chief Executive Officer and Vice president and Chief Financial Officer of Kinder
Morgan Management, LLC, the delegate of Kinder Morgan, G.P., Inc., our general
partner, executed certifications in connection with our Form 10-Q for the period
ending June 30, 2002 pursuant to the Sarbanes-Oxley Act of 2002. Copies of such
certifications were filed as exhibits pursuant to Item 7.
Current report dated August 14, 2002 on Form 8-K was filed on August 14,
2002, pursuant to Item 9 of that form. We provided notice that we, along with
Kinder Morgan, Inc., a subsidiary of which serves as our general partner, and
Kinder Morgan Management, LLC, a subsidiary of our general partner that manages
and controls our business and affairs, intended to make presentations on August
14, 2002 at the UBS Warburg Equity Investor Tour to investors, analysts and
others to address various strategic and financial issues relating to the
business plans and objectives of us, Kinder Morgan, Inc. and Kinder Morgan
Management, LLC. Notice was also given that prior to the meeting, interested
parties would be able to view the materials presented at the meetings by
visiting Kinder Morgan, Inc.'s website at:
http://www.kindermorgan.com/investor_relations/presentations/.
Current report dated August 26, 2002 on Form 8-K was filed on August 26,
2002, pursuant to Item 7 of that form. We filed, as exhibits pursuant to Item 7,
the consolidated balance sheets as of June 30, 2002 and December 31, 2001, of
Kinder Morgan G.P., Inc., our general partner and a wholly-owned subsidiary of
Kinder Morgan, Inc.
Current report dated September 4, 2002 on Form 8-K was filed on September 4,
2002, pursuant to Item 9 of that form. We provided notice that we, along with
Kinder Morgan, Inc., a subsidiary of which serves as our general partner, and
Kinder Morgan Management, LLC, a subsidiary of our general partner that manages
and controls our business and affairs, intended to make presentations on
September 4, 2002 at the Lehman Brothers' 2002 CEO Energy/Power Conference to
investors, analysts and others to address various strategic and financial issues
relating to the business plans and objectives of us, Kinder Morgan, Inc. and
Kinder Morgan Management, LLC. Notice was
46
also given that prior to the meeting, interested parties would be able to view
the materials presented at the meetings by visiting Kinder Morgan, Inc.'s
website at: http://www.kindermorgan.com/investor_relations/presentations/.
Interested parties would also be able to access the presentations by audio
webcast, both live and on-demand. Live webcast presentations could be accessed
at: http://customer.ibeam.com/lehm003/090302a_byRFD/, by choosing the webcast
link and completing the registration page. The on-demand webcast (replay) for
the presentations would be available for three months, and could also be
accessed at: http://customer.ibeam.com/lehm003/090302a_byRFD/.
Current report dated September 17, 2002 on Form 8-K was filed on September
18, 2002, pursuant to Item 9 of that form. We provided notice that we, along
with Kinder Morgan, Inc., a subsidiary of which serves as our general partner,
and Kinder Morgan Management, LLC, a subsidiary of our general partner that
manages and controls our business and affairs, intended to make presentations on
September 19, 2002 at the Global Power & Gas Leaders Conference to investors,
analysts and others to address various strategic and financial issues relating
to the business plans and objectives of us, Kinder Morgan, Inc. and Kinder
Morgan Management, LLC. Notice was also given that prior to the meeting,
interested parties would be able to view the materials presented at the meetings
by visiting Kinder Morgan, Inc.'s website at:
http://www.kindermorgan.com/investor_relations/presentations/. Interested
parties would also be able to access the presentations by audio webcast, both
live and on-demand. Live webcast presentations could be accessed at:
http://twst.com/econf/mm/merrill3/morgan.html, by choosing the webcast link and
completing the registration page. The on-demand webcast (replay) for the
presentations would be available for fourteen days, and could also be accessed
at: http://twst.com/econf/mm/merrill3/morgan.html.
47
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 thereunto duly authorized.
KINDER MORGAN ENERGY PARTNERS, L.P.
(A Delaware limited partnership)
By: KINDER MORGAN G.P., INC.,
its General Partner
By: KINDER MORGAN MANAGEMENT, LLC,
its Delegate
/s/ C. Park Shaper
------------------------------
C. Park Shaper
Vice President, Treasurer and Chief Financial Officer
(Duly Authorized Officer and Principal Financial and
Accounting Officer)
Date: November 13, 2002
48
CERTIFICATIONS
I, Richard D. Kinder, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Kinder Morgan Energy
Partners, L.P.;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this quarterly report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
/s/ Richard D. Kinder
------------------------------
Richard D. Kinder
Chairman and Chief Executive Officer
Date: November 13, 2002
49
I, C. Park Shaper, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Kinder Morgan Energy
Partners, L.P.;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this quarterly report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
/s/ C. Park Shaper
------------------------------
C. Park Shaper
Vice President, Treasurer and Chief Financial Officer
Date: November 13, 2002
50