UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2000
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 of (I.R.S. Employer Identification
incorporation or organization) Number)
500 Dallas St.
Suite 1000
Houston, Texas 77002
- ------------------------------- ------------------------------------
(Address of principal executive (Zip Code)
Offices)
(713) 369-9000
------------------------------------------------------------
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes [X] No [ ]
The Registrant had 64,215,909 units outstanding at November 8, 2000.
Page 1 of 26
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
TABLE OF CONTENTS
Page No.
--------
PART I. FINANCIAL INFORMATION
ITEM 1. - Financial Statements (Unaudited)
Consolidated Statements of Income - Three
and Nine Months Ended September 30, 2000 and 1999 3
Consolidated Balance Sheets - September 30, 2000 and
December 31, 1999 4
Consolidated Statements of Cash Flows - Nine Months
Ended September 30, 2000 and 1999 5
Notes to Consolidated Financial Statements 6
ITEM 2. - Management's Discussion and Analysis of
Financial Condition and Results of Operations 17
ITEM 3. - Quantitative and Qualitative Disclosures about
Market Risk 24
PART II. OTHER INFORMATION
ITEM 1. - Legal Proceedings 25
ITEM 2. - Changes in Securities and Use of Proceeds 25
ITEM 3. - Defaults Upon Senior Securities 25
ITEM 4. - Submission of Matters to a Vote of Security Holders25
ITEM 5. - Other Information 25
ITEM 6. - Exhibits and Reports on Form 8-K 25
Page 2 of 26
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands Except Per Unit Amounts)
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
------------- ------------- ------------- -------------
Revenues $ 202,575 $ 104,388 $ 553,691 $ 307,370
Costs and Expenses
Operations and maintenance 80,914 31,907 207,968 91,813
Depreciation and amortization 20,951 11,617 59,700 34,523
General and administrative 15,052 7,940 44,755 24,700
Taxes, other than income taxes 5,832 4,093 18,405 12,518
------------- ------------- ------------- -------------
122,749 55,557 330,828 163,554
------------- ------------- ------------- -------------
Operating Income 79,826 48,831 222,863 143,816
Other Income (Expense)
Earnings from equity investments 20,568 13,400 52,747 31,101
Amortization of excess cost of equity investments (2,174) (1,396) (6,021) (2,835)
Interest, net (24,115) (14,197) (66,030) (38,180)
Other, net 2,060 2,524 13,803 4,411
Gain on sale of equity interest, net of special charges - 10,063 - 10,063
Minority Interest (2,216) (868) (5,985) (2,294)
------------- ------------- ------------- -------------
Income Before Income Taxes and Extraordinary Charge 73,949 58,357 211,377 146,082
Income Taxes (4,089) (3,209) (10,148) (6,752)
Income Before Extraordinary Charge 69,860 55,148 201,229 139,330
Extraordinary Charge on Early Extinguishment of Debt - (2,595) - (2,595)
------------- ------------- ------------- -------------
Net Income $ 69,860 $ 52,553 $ 201,229 $ 136,735
============= ============= ============= =============
Calculation of Limited Partners' Interest in Net Income:
Income Before Extraordinary Charge $ 69,860 $ 55,148 $ 201,229 $ 139,330
Less: General Partner's interest in Net Income (26,985) (14,797) (76,245) (41,545)
------------- ------------- ------------- -------------
Limited Partners' Net Income before Extraordinary Charge 42,875 40,351 124,984 97,785
Less: Extraordinary Charge on Early Extinguishment of Debt - (2,595) - (2,595)
------------- ------------- ------------- -------------
Limited Partners' Net Income $ 42,875 $ 37,756 $ 124,984 $ 95,190
============= ============= ============= =============
Net Income per Unit before Extraordinary Charge $ 0.67 $ 0.82 $ 2.00 $ 2.00
============= ============= ============= =============
Extraordinary Charge per Unit $ - $ (0.05) $ - $ (0.05)
============= ============= ============= =============
Basic and Diluted Net Income per Unit $ 0.67 $ 0.77 $ 2.00 $ 1.95
============= ============= ============= =============
Number of Units used in Computation 64,213 48,927 62,602 48,854
============= ============= ============= =============
The accompanying notes are an integral part of these consolidated financial
statements.
Page 3 of 26
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands)
(Unaudited)
September 30, December 31,
2000 1999
--------------- ---------------
ASSETS
Current Assets
Cash and cash equivalents $ 37,556 $ 40,052
Accounts and notes receivable
Trade 116,535 71,738
Related parties 15,819 45
Inventories
Products 7,207 8,380
Materials and supplies 4,720 4,703
Gas imbalances 19,774 7,014
Other current assets 1,977 -
--------------- ---------------
203,588 131,932
--------------- ---------------
Property, Plant and Equipment, at cost 3,082,875 2,696,122
Less accumulated depreciation 174,895 117,809
--------------- ---------------
2,907,980 2,578,313
--------------- ---------------
Equity Investments 342,145 418,651
--------------- ---------------
Notes receivable 9,460 10,041
Intangibles 111,724 56,630
Deferred charges and other assets 32,458 33,171
--------------- ---------------
TOTAL ASSETS $ 3,607,355 $ 3,228,738
=============== ===============
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Accounts payable
Trade $ 46,898 $ 15,692
Related parties 245 3,569
Current portion of long-term debt - 209,200
Accrued rate refunds 5,666 36,607
Accrued interest 11,676 10,014
Accrued right-of-way liabilities 8,163 7,039
Accrued taxes 11,409 8,870
Gas imbalances 15,432 6,189
Accrued other liabilities 28,067 21,981
--------------- ---------------
127,556 319,161
--------------- ---------------
Long-Term Liabilities and Deferred Credits
Long-term debt 1,354,910 989,101
Other 105,474 97,379
--------------- ---------------
1,460,384 1,086,480
--------------- ---------------
Commitments and Contingencies
Minority Interest 53,195 48,299
--------------- ---------------
Partners' Capital
Common Units 1,938,583 1,759,142
General Partner 27,637 15,656
--------------- ---------------
1,966,220 1,774,798
--------------- ---------------
TOTAL LIABILITIES AND PARTNERS' CAPITAL $ 3,607,355 $ 3,228,738
=============== ===============
The accompanying notes are an integral part of these consolidated financial
statements.
Page 4 of 26
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)
Nine Months Ended September 30,
2000 1999
--------------- ---------------
Cash Flows From Operating Activities
Reconciliation of net income to net cash provided by
operating activities
Net income $ 201,229 $ 136,735
Extraordinary charge on early extinguishment of debt - 2,595
Depreciation and amortization 59,700 34,523
Amortization of excess cost of equity investments 6,021 2,835
Earnings from equity investments (52,747) (31,101)
Distributions from equity investments 36,055 25,082
Gain on sale of equity interest, net of special charges - (10,063)
Changes in components of working capital (10,715) (6,370)
Rate refunds settlement (47,901) -
Other, net 1,185 (9,428)
--------------- ---------------
Net Cash Provided by Operating Activities 192,827 144,808
--------------- ---------------
Cash Flows From Investing Activities
Acquisitions of assets (573,394) (13,984)
Additions to property, plant and equipment for
expansion and maintenance projects (81,857) (61,696)
Sale of investments, property, plant and equipment,
net of removal costs 8,211 42,870
Changes in gas stored underground 433 -
Acquisitions of equity investments - (124,163)
Contributions to equity investments (412) (800)
--------------- ---------------
Net Cash Used in Investing Activities (647,019) (157,773)
--------------- ---------------
Cash Flows From Financing Activities
Issuance of debt 1,430,286 424,734
Payment of debt (946,307) (270,444)
Debt issue costs (1,689) (3,611)
Proceeds from issuance of common units 171,410 -
Contributions from General Partner's Minority Interest 7,434 156
Distributions to partners
Common Units (140,107) (100,073)
General Partner (64,263) (37,896)
Minority Interest (5,795) (1,660)
Other, net 727 (232)
--------------- ---------------
Net Cash Provided by Financing Activities 451,696 10,974
--------------- ---------------
Increase in Cash and Cash Equivalents (2,496) (1,991)
Cash and Cash Equivalents, Beginning of Period 40,052 31,735
--------------- ---------------
Cash and Cash Equivalents, End of Period $ 37,556 $ 29,744
=============== ===============
Noncash Investing and Financing Activities
Contribution of net assets to partnership investments $ - $ 20
Assets acquired by the issuance of Common Units $ 23,319 $ 15,304
Assets acquired by the assumption of liabilities $ 41,342 $ -
The accompanying notes are an integral part of these consolidated
financial statements.
Page 5 of 26
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. 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. 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 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, 1999.
We computed Net Income per Unit by dividing the Limited Partners' interest
in Net Income by the weighted average number of units outstanding during the
periods.
2. Acquisitions and Joint Ventures
During 1999 and the first nine months of 2000, we completed the following
significant acquisitions. The results of operations from these acquisitions are
included in the consolidated financial statements from the date of acquisition.
Plantation Pipe Line Company
On September 15, 1998, we acquired an approximate 24% interest in
Plantation Pipe Line Company for $110 million. On June 16, 1999, we acquired an
additional approximate 27% interest in Plantation Pipe Line Company for $124.2
million. Collectively, we now own approximately 51% of Plantation Pipe Line
Company, and ExxonMobil Pipeline Company, an affiliate of ExxonMobil
Corporation, owns approximately 49%. Plantation Pipe Line Company owns and
operates a 3,100-mile pipeline system throughout the southeastern United States.
The pipeline is a common carrier of refined petroleum products to various
metropolitan areas, including Atlanta, Georgia; Charlotte, North Carolina; and
the Washington, D.C. area. We do not control Plantation Pipe Line Company, and
therefore, we account for our investment in Plantation under the equity method
of accounting. Plantation Pipe Line Company is part of our Product Pipelines
business segment.
Transmix Operations
On September 10, 1999, we acquired transmix processing plants in Richmond,
Virginia and Dorsey Junction, Maryland and other related assets from Primary
Corporation. As consideration for the purchase, we paid Primary $18.25 million
(before purchase price adjustments) and 510,147 units valued at approximately
$14.3 million. The petroleum products refining and marketing activities of the
transmix operations are included as part of our Product Pipelines business
segment.
Trailblazer Pipeline Company
Effective November 30, 1999, we acquired a 33 1/3% interest in Trailblazer
Pipeline Company for $37.6 million from Columbia Gulf Transmission Company, an
affiliate of Columbia Energy Group. Trailblazer is an Illinois partnership that
owns and operates a 436-mile natural gas pipeline system that traverses from
Colorado through southeastern Wyoming to Beatrice, Nebraska. Trailblazer has a
certificated capacity of 492 million cubic feet per day ("MMcf/d") of natural
gas. For the month of December 1999, we accounted for our 33 1/3% interest in
Trailblazer under the equity method of accounting. Effective December 31, 1999,
following our acquisition of an additional 33 1/3% interest in Trailblazer,
which is discussed below, Trailblazer's activities were included as part of
Page 6 of 26
our consolidated financial statements. Since December 31, 1999, we have reported
Trailblazer's activities as part of our Natural Gas Pipelines business segment.
Kinder Morgan, Inc. Asset Contributions
Effective December 31, 1999, we acquired over $700 million of assets from
Kinder Morgan, Inc. We paid KMI $330 million and 9.81 million units as
consideration for the assets. We acquired Kinder Morgan Interstate Gas
Transmission LLC (formerly K N Interstate Gas Transmission Co.), a 33 1/3%
interest in Trailblazer and a 49% equity interest in Red Cedar Gathering
Company. The acquired interest in Trailblazer, when combined with the interest
purchased on November 30, 1999, gave us a 66 2/3% ownership interest. The
transaction was accounted for under the purchase method of accounting, and
going forward from December 31, 1999, these assets have been included in our
Natural Gas Pipelines business segment.
Bulk Terminals
Effective January 1, 2000, we acquired all of the shares of the capital
stock of Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc. We paid
an aggregate consideration of approximately $24.1 million, including 574,172
units and approximately $0.8 million in cash. Our acquisition of the two
entities was accounted for under the purchase method of accounting, and going
forward from January 1, 2000, their results have been included as part of our
Bulk Terminals business segment.
Kinder Morgan CO2 Company, L.P.
Effective April 1, 2000, we acquired from affiliates of Shell Exploration
& Production Company the 80% of Shell CO2 Company, Ltd. that we did not own for
$212.1 million. We renamed the limited partnership Kinder Morgan CO2 Company,
L.P., and going forward from April 1, 2000, its results have been reported as
part of our CO2 Pipelines business segment.
CO2 Pipelines Asset Acquisitions
Effective June 1, 2000, we acquired significant interests in CO2 pipeline
assets and oil-producing properties from Devon Energy Production Company L.P.
for $55 million, before purchase price adjustments. Included in the acquisition
was an approximate 81% equity interest in the Canyon Reef Carriers CO2 Pipeline,
an approximate 71% working interest in the SACROC Unit, and minority interests
in the Sharon Ridge Unit and the Reinecke Unit. All of the assets and properties
are located in the Permian Basin of west Texas. Since June 1, 2000, these assets
have been included as part of our CO2 Pipelines business segment.
Pro Forma Information
The following summarized unaudited Pro Forma Consolidated Income Statement
information for the nine months ended September 30, 2000 and 1999, assumes the
above acquisitions had occurred as of January 1, 1999. These unaudited Pro Forma
financial results have been prepared for comparative purposes only and may not
be indicative of the results that would have occurred if we had completed the
above acquisitions on the dates indicated or the results which will be attained
in the future. Amounts presented below are in thousands, except for the per unit
amounts:
Pro Forma
Nine Months Ended
Income Statement Sept. 30, 2000 Sept. 30, 1999
---------------- -------------- --------------
(Unaudited)
Revenues $593,153 $521,460
Operating Income $235,957 $235,576
Net Income before Extraordinary
Charge $212,854 $214,621
Net Income $212,854 $212,026
Net Income per Unit before
Extraordinary Charge $2.05 $2.08
Net Income per Unit $2.05 $2.04
Page 7 of 26
3. Gain on Sale of Equity Interest, Net of Special Charges
During the third quarter of 1999, we completed the sale of our partnership
interest in the Mont Belvieu fractionation facility for approximately $41.8
million. We recognized a gain of $14.1 million on the sale. We included the gain
as part of our Natural Gas Pipelines business segment. Offsetting the gain
amount were charges of approximately $3.6 million relating to the write-off of
abandoned project costs, primarily within the Products Pipelines, and a charge
of $0.4 million relating to prior years' over-billed storage tank lease fees,
also within our Product Pipelines segment.
4. Litigation and Other Contingencies
Federal Energy Regulatory Commission Proceedings
SFPP, L.P. is the partnership that owns our Pacific pipelines. Tariffs
charged by SFPP are subject to certain proceedings involving shippers' protests
regarding the interstate rates, as well as practices and the jurisdictional
nature of certain facilities and services, on our Pacific Operations' pipeline
systems. In September 1992, El Paso Refinery, L.P. filed a protest/complaint
with the Federal Energy Regulatory Commission:
o challenging SFPP's East Line rates from El Paso, Texas to Tucson and
Phoenix, Arizona;
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 dates following El Paso Refinery's September 1992 filing, 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 West
Lines. These shippers include:
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 charge
at SFPP's Watson origin pump station in Carson, California was charged in
violation of the Interstate Commerce Act. In subsequent procedural rulings, the
FERC consolidated these challenges (Docket Nos. OR92-8-000, et al.) and ruled
that they must proceed as a complaint proceeding, with the burden of proof being
placed on the complaining parties. These parties must show that SFPP's rates and
practices at issue violate the requirements of the Interstate Commerce Act.
Hearings in the FERC proceeding were held in 1996 and an initial decision
by the FERC administrative law judge was issued on September 25, 1997. The
initial decision upheld SFPP's position that "changed circumstances" were not
shown to exist on the West Line, thereby retaining the just and reasonable
status of all West Line rates that were "grandfathered" under the Energy Policy
Act of 1992. Accordingly, the administrative law judge ruled that these rates
are not subject to challenge, either for the past or prospectively, in that
proceeding. The administrative law judge's decision specifically excepted from
that ruling 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.
The initial decision also included rulings that were 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
under FERC Opinion 154-B;
o the level of income tax allowance; and
o the recoverability of civil and regulatory litigation expense and certain
pipeline reconditioning costs.
The administrative law judge also ruled that the gathering enhancement
service at SFPP's Watson origin pump station was subject to FERC jurisdiction
and ordered that a tariff for that service and supporting cost of service
Page 8 of 26
documentation be filed no later than 60 days after a final FERC order on this
matter.
On January 13, 1999, the FERC issued its Opinion No. 435, which affirmed
in part and modified in part the initial decision. In Opinion No. 435, the FERC
ruled 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 one "non-grandfathered" West Line tariff 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 reversed in part and
affirmed in part the initial decision's ruling regarding the methodology for
calculating the rate base for the East Line. Opinion No. 435 modified the
initial decision concerning the date on which the starting rate base should be
calculated and the accumulated deferred income tax and allowable cost of equity
used to calculate the rate base. In addition, Opinion No. 435 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. On January 19, 1999,
ARCO filed a petition with the United States Court of Appeals for the District
of Columbia Circuit for review of Opinion No. 435. SFPP and a number of the
complainants each sought rehearing by FERC of elements of Opinion No. 435. In
compliance with Opinion No. 435, on March 15, 1999, SFPP submitted a compliance
filing implementing the rulings made by FERC, establishing the level of rates to
be charged by SFPP in the future, and setting forth the amount of reparations
owed by SFPP to the complainants under the order. The complainants contested
SFPP's compliance filing.
SFPP and certain complainants sought rehearing of Opinion No. 435 by the
FERC, asking that a number of rulings be modified. On May 17, 2000, the FERC
issued its Opinion No. 435-A, which ruled on the requests for rehearing and
modified Opinion No. 435 in certain respects. It denied requests to reverse its
prior rulings that SFPP's West Line rates and Watson Station gathering
enhancement facilities charge are entitled to be treated as just and reasonable
"grandfathered" rates under the Energy Policy Act. It suggested, however, that
if SFPP had fully recovered the capital costs of the Watson Station 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 the computation 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
between SFPP and 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. This policy requires customers to demonstrate a need
for additional capacity if a shortage of available pipeline space exits.
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
Page 9 of 26
charge, but required SFPP to pay refunds to the extent that the compliance
tariff East Line rates are higher than the rates produced under Opinion No.
435-A.
In June 2000, several parties filed requests for rehearing of certain
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 1994-98 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.
ARCO, Chevron, Navajo, RHC, Texaco and SFPP sought judicial review of
Opinion No. 435-A in the United States Court of Appeals for the District of
Columbia Circuit. The FERC moved to:
o consolidate those petitions with prior ARCO and RHC petitions to review
Opinion No. 435;
o dismiss the Chevron, RHC and SFPP petitions; and
o hold the other petitions in abeyance pending ruling on the requests for
rehearing of Opinion No. 435-A.
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 containing East Line rates based on those rulings. On August 16, 2000,
the FERC directed SFPP to supplement its compliance filing by providing certain
underlying workpapers and information; SFPP responded to that order on August
31, 2000.
On September 19, 2000, the Court of Appeals dismissed Chevron's petition
for lack of prosecution. On October 20, 2000, the court dismissed the petitions
for review filed by SFPP and RHC as premature in light of their pending requests
for FERC rehearing, consolidated the ARCO, Navajo and Texaco petitions for
review with the petitions for review of Opinion No. 435, and ordered that
proceedings be held in abeyance until after FERC action on the rehearing
requests.
In December 1995, Texaco filed an additional FERC complaint, which
involves the question of whether a tariff filing was required for movements on
SFPP's Sepulveda Lines, which are upstream of its Watson, California station
origin point, and, if so, whether those rates may be set in that proceeding and
what those rates should be. Several other West Line shippers have filed similar
complaints and/or motions to intervene in this proceeding, all of which have
been consolidated into Docket Nos. OR96-2-000, et al. Hearings before an
administrative law judge were held in December 1996 and the parties completed
the filing of final post-hearing briefs in January 1997.
On March 28, 1997, the administrative law judge issued an initial decision
holding that the movements on the Sepulveda Lines are not subject to FERC
jurisdiction. On August 5, 1997, the FERC reversed that decision and found the
Sepulveda Lines to be subject to the jurisdiction of the FERC. The FERC ordered
SFPP to make a tariff filing within 60 days to establish an initial rate for
these facilities. The FERC reserved decision on reparations until it ruled on
the newly-filed rates. On October 6, 1997, SFPP filed a tariff establishing the
initial interstate rate for movements on the Sepulveda Lines from Sepulveda
Junction to Watson Station at the preexisting rate of five cents per barrel,
along with supporting cost of service documentation. Subsequently, several
shippers filed protests and motions to intervene at the FERC challenging that
rate. On December 24, 1997, FERC denied SFPP's request for rehearing of the
August 5, 1997 decision. On December 31, 1997, SFPP filed an application for
market power determination, which, if granted, will enable it to charge
market-based rates for this service. Several parties protested SFPP's
application. On September 30, 1998, the FERC issued an order finding that, based
on SFPP's application, SFPP lacks market power in the Watson Station destination
market served by the Sepulveda Lines. The FERC found that SFPP appeared to lack
market power in the origin market served by the Sepulveda Lines as well, but
established a hearing to permit the protesting parties to substantiate
allegations that SFPP possesses market power in the origin market. Hearings
before a FERC administrative law judge on this limited issue were held in
February 2000. The matter has been briefed to the administrative law judge and
SFPP is awaiting the judge's issuance of an initial decision.
On October 22, 1997, ARCO, Mobil and Texaco filed another complaint at the
FERC (Docket No. OR98-1-000) challenging the justness and reasonableness of all
of SFPP's interstate rates. The complaint again challenges
Page 10 of 26
SFPP's East and West Line rates and raises many of the same issues, including a
renewed challenge to the grandfathered status of West Line rates, that have been
at issue in Docket Nos. OR92-8-000, et al. The complaint includes an assertion
that the acquisition of SFPP and the cost savings anticipated to result from the
acquisition constitute "substantially changed circumstances" that provide a
basis for terminating the "grandfathered" status of SFPP's otherwise protected
rates. The complaint also seeks to establish that SFPP's grandfathered
interstate rates from the San Francisco Bay area to Reno, Nevada and from
Portland to Eugene, Oregon are also subject to "substantially changed
circumstances" and, therefore, are subject to challenge. In November 1997,
Ultramar Diamond Shamrock Corporation filed a similar complaint at the FERC
(Docket No. OR98-2-000, et al.). The shippers are seeking both reparations and
prospective rate reductions for movements on all of the lines.
SFPP filed answers to both complaints, and on January 20, 1998, the FERC
issued an order accepting the complaints and consolidating both complaints into
one proceeding, but holding them in abeyance pending a Commission decision on
review of the initial decision in Docket Nos. OR92-8-000, et al. In July 1998,
some complainants amended their complaints to incorporate updated financial and
operational data on SFPP. SFPP answered the amended complaints. In a companion
order to Opinion No. 435, the FERC directed the complainants to amend their
complaints, as may be appropriate, consistent with the terms and conditions of
its orders, including Opinion No. 435. On January 10 and 11, 2000, the
complainants again amended their complaints to incorporate further updated
financial and operational data on SFPP. SFPP filed an answer to these amended
complaints on February 15, 2000. On May 17, 2000, the FERC issued an order
finding that the various complaining parties had alleged sufficient grounds for
their complaints against SFPP's interstate rates to go forward to a hearing. At
such hearing, the administrative law judge will 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.
Discovery in this new proceeding is currently being conducted, with a
hearing scheduled for August 2001 and an initial decision by the administrative
law judge due in January 2002.
In August 2000, Navajo and RHC filed new complaints against SFPP's East
Line rates and Ultramar filed an additional complaint updating its pre-existing
challenges to SFPP's interstate pipeline rates. SFPP answered the complaints,
and on September 22, 2000, the FERC issued an order accepting these new
complaints and consolidating them with the ongoing proceeding in Docket No.
OR96-2-000, et al.
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 make "grandfathered" rates subject to challenge. The complainants
have alleged a variety of grounds for finding "substantially changed
circumstances," including the acquisition of SFPP and cost savings achieved
subsequent to the acquisition. 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 may lose their "grandfathered"
status. If these rates are found to be unjust and unreasonable, shippers may be
entitled to a prospective rate reduction together with reparations for periods
from the date of the complaint to the date of the implementation of the new
rates.
We are not able to predict with certainty the final outcome of the FERC
proceedings, 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 we have adequately reserved for all current
proceedings.
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
Page 11 of 26
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.
Procedurally, the rehearing complaint will be heard first, followed by
consideration of the April 2000 complaint and SFPP's market-based application,
which have been consolidated for hearing by the CPUC. The rehearing complaint
was the subject of evidentiary hearings in October 2000, and a decision is
expected within six months. The April 2000 complaint and SFPP's market-based
application will be the subject of evidentiary hearings in February 2001, with a
decision expected within six months of the hearings.
We believe we have adequate reserves recorded for any adverse decision
related to this matter.
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 is accruing amounts for payment of the
rental for the subject rights-of-way consistent with our expectations of the
ultimate outcome of the proceeding.
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 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
thereunder, 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:
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; and
o several ground water hydrocarbon remediation efforts under administrative
orders issued by the California Regional Water Quality Control Board and two
other state agencies.
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 or natural gas liquids. Among these matters
is a lawsuit originally filed in February 1998 against SFPP in the Superior
Court of the State of California in and for the County of Solano by 283
individual plaintiffs alleging personal injury and property damage arising from
a release
Page 12 of 26
in 1996 of petroleum products from SFPP's pipeline running through Elmira,
California. An amended complaint was filed on May 22, 1998. Settlement was
negotiated in the third quarter of 2000 and has been reached with the
plaintiff's attorneys on issues related to this case.
Review of assets related to Kinder Morgan Interstate Gas Transmission LLC
includes the environmental impacts from petroleum and used oil releases to the
soil and groundwater at five sites. Further delineation and remediation of these
impacts will be conducted. A reserve was established to address the closure of
these issues.
Although no assurance can be given, we believe that the ultimate
resolution of all these environmental matters set forth in this Note 4 will not
have a material adverse effect on our financial position or results of
operations. We have recorded a reserve for environmental claims in the amount of
$16.9 million at September 30, 2000.
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 financial position or our results
of operations.
For more detailed information regarding these proceedings and other
litigation, please refer to our 1999 Form 10-K, Note 16 of the Notes to the
Consolidated Financial Statements.
5. Distributions
On August 14, 2000, we paid a cash distribution for the quarterly period
ended June 30, 2000, of $0.85 per unit. The distribution was declared on July
20, 2000, payable to unitholders of record as of July 31, 2000.
On October 19, 2000, we declared a cash distribution for the quarterly
period ended September 30, 2000, of $0.85 per unit. The distribution will be
paid on or before November 14, 2000, to unitholders of record as of October 31,
2000.
6. Debt
Our debt facilities as of September 30, 2000, consist primarily of:
o a $300 million unsecured five-year credit facility;
o a $300 million unsecured 364-day credit facility;
o $250 million of 6.30% Senior Notes due February 1, 2009;
o $200 million of 8.00% Senior Notes due March 15, 2005;
o $200 million of Floating Rate Senior Notes due March 22, 2002;
o $181 million of Series F First Mortgage Notes (our subsidiary, SFPP, is the
obligor on the notes);
o $20.2 million of Senior Secured Notes (our subsidiary, Trailblazer, is the
obligor on the notes);
o $23.7 million of tax-exempt bonds due 2024 (our subsidiary, Kinder Morgan
Operating L.P. "B" ("OLP-B"), is the obligor on these bonds);
o a $10 million unsecured 364-day credit facility of Trailblazer; and
o $300 million in short-term commercial paper.
On August 11, 2000, we refinanced the outstanding balance under SFPP's
secured credit facility with a $175.0 million borrowing under our five-year
credit facility. Upon refinancing, SFPP executed a $175 million intercompany
note in favor of Kinder Morgan Energy Partners, L.P. At September 30, 2000, we
had $257 million borrowed under the five-year credit facility, and the interest
rate was 7.095%.
Our 364-day credit facility expired on September 29, 2000 and was extended
until October 25, 2000. No borrowings were outstanding under our 364-day credit
facility at September 30, 2000. On October 25, 2000, the facility was replaced
with a new $600 million unsecured 364-day credit facility. The terms of the new
credit facility are substantially similar to the terms of the previous facility.
In conjunction with the new credit facility, we also increased our commercial
paper program to provide for the issuance of up to $600 million of commercial
paper. At September 30, 2000, we had $211.6 million of commercial paper
outstanding.
Page 13 of 26
At September 30, 2000, the outstanding balance under Trailblazer's
revolving credit agreement was $10 million. The agreement provides for an
interest rate of LIBOR plus 0.875%. At September 30, 2000, the interest rate on
the credit facility debt was 7.49563%.
For the quarter ended September 30, 2000, the weighted-average interest
rate on OLP-B's tax-exempt bonds issued by the Jackson-Union Counties Regional
Port District was 4.42% per annum.
On November 8, 2000, we closed on a private placement of $250 million of
10-year notes bearing a coupon of 7.5%. We agreed to offer to exchange these
notes with substantially identical notes that are registered under the
Securities Act of 1933 within 210 days of the close of this transaction. The
proceeds from this offering, net of underwriting discounts, were $246,792,500.
These proceeds were used to reduce our outstanding commercial paper.
7. Partners' Capital
At December 31, 1998, we had 48,821,690 units outstanding. On January 21,
1999, and January 29, 1999, we repurchased and immediately cancelled 4,000 and
2,000 units, respectively. On August 30, 1999, we issued 600 units associated
with unit option exercises, and on September 10, 1999, we issued 510,147 units
in connection with the acquisition of net assets from Primary Corporation. At
September 30, 1999, we had 49,326,437 units outstanding.
At December 31, 1999, we had 59,137,137 units outstanding. On February 2,
2000, we issued 574,172 units for the acquisition of Milwaukee Bulk Terminals,
Inc. and Dakota Bulk Terminal, Inc. Additionally, 400 units were issued on each
of February 7, 2000 and February 23, 2000, in accordance with unit option
exercises. On April 4, 2000, we issued 4,500,000 units in a public offering at
an issuance price of $39.75 per unit, less commissions and underwriting
expenses. We used the proceeds from the April 2000 unit issuance to acquire the
remaining ownership interest in Kinder Morgan CO2 Company, L.P. Due to the
exercise of additional unit options, we issued 400 units on July 25, 2000 and
2,800 units on September 1, 2000. At September 30, 2000, we had 64,215,309 units
outstanding.
These units represent the limited partners' interest and an effective 98%
economic interest in the Partnership, exclusive of our general partner's
incentive distribution. The general partner has an effective 2% interest in the
Partnership, excluding the general partner's incentive distribution.
For the purposes of maintaining partner capital accounts, our partnership
agreement specifies that items of income and loss 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 allocated to our general partner are determined by
the amount quarterly distributions to unitholders exceed certain specified
target levels. Our cash distribution of $0.85 per unit paid on August 14, 2000
for the second quarter of 2000 required an incentive distribution to our general
partner of $26,550,589. Our cash distribution of $0.70 per unit paid on August
13, 1999 for the second quarter of 1999 required an incentive distribution to
our general partner of $13,083,847. The increased incentive distribution to our
general partner paid for the second quarter of 2000 over the distribution paid
for the second quarter of 1999 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 2000 of $0.85 per unit
will result in an incentive distribution to our general partner of $26,551,994.
This compares to our cash distribution of $0.725 per unit and incentive
distribution to our general partner of $14,416,532 for the third quarter of
1999. The increased incentive distribution to our general partner paid for the
third quarter of 2000 over the distribution paid for the third quarter of 1999
reflects the increase in the amount distributed per unit as well as the issuance
of additional units.
8. Reportable Segments
Page 14 of 26
We compete in four reportable business segments:
o Product Pipelines;
o Natural Gas Pipelines;
o CO2 Pipelines; and
o Bulk Terminals.
We evaluate performance based on each segments' earnings, which excludes
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.
Financial information by segment follows (in thousands):
Three Months Ended Sept. 30, Nine Months Ended Sept. 30,
2000 1999 2000 1999
------------ ------------ ------------ ------------
Revenues
Products Pipelines $ 93,453 $ 76,275 $ 274,775 $ 220,961
Natural Gas Pipelines 45,984 - 126,098 -
CO2 Pipelines 30,007 - 54,626 -
Bulk Terminals 33,131 28,113 98,192 86,409
------------ ------------ ------------ ------------
Total Segments $ 202,575 $ 104,388 $ 553,691 $ 307,370
============ ============ ============ ============
Operating expenses
Products Pipelines $ 33,763 $ 15,825 $ 98,184 $ 42,815
Natural Gas Pipelines 15,585 - 33,648 -
CO2 Pipelines 10,271 - 16,068 -
Bulk Terminals 21,295 16,082 60,068 48,998
------------ ------------ ------------ ------------
Total Segments $ 80,914 $ 31,907 $ 207,968 $ 91,813
============ ============ ============ ============
Operating income
Products Pipelines $ 45,994 $ 47,647 $ 135,499 $ 139,652
Natural Gas Pipelines 25,463 38 73,613 -
CO2 Pipelines 14,949 (2) 30,465 (4)
Bulk Terminals 8,472 9,088 28,041 28,870
------------ ------------ ------------ ------------
Total Segments $ 94,878 $ 56,771 $ 267,618 $ 168,518
============ ============ ============ ============
Earnings from equity investments, net of amortization of excess costs
Products Pipelines $ 9,708 $ 7,060 $ 22,684 $ 14,881
Natural Gas Pipelines 3,798 1,320 11,228 2,500
CO2 Pipelines 4,888 3,622 12,814 10,866
Bulk Terminals - 2 - 19
------------ ------------ ------------ ------------
Total Segments $ 18,394 $ 12,004 $ 46,726 $ 28,266
============ ============ ============ ============
Page 15 of 26
Three Months Ended Sept. 30, Nine Months Ended Sept. 30,
2000 1999 2000 1999
------------ ------------ ------------ ------------
Segment earnings
Products Pipelines $ 52,795 $ 50,955 $ 159,805 $ 149,827
Natural Gas Pipelines 29,567 15,486 85,200 16,553
CO2 Pipelines 19,838 3,620 44,026 10,849
Bulk Terminals 9,043 8,092 28,968 27,279
------------ ------------ ------------ ------------
Total Segments (1) $ 111,243 $ 78,153 $ 317,999 $ 204,508
============ ============ ============ ============
Sept. 30, Dec. 31,
Business Segment Assets 2000 1999
------------ ------------
Products Pipelines $ 2,030,252 $ 2,015,995
Natural Gas Pipelines 915,969 879,076
CO2 Pipelines 379,008 86,684
Bulk Terminals 229,949 203,601
------------ ------------
Total Segments (2) $ 3,555,178 $ 3,185,356
============ ============
(1) The following reconciles segment earnings to net income.
Three Months Ended Sept. 30, Nine Months Ended Sept. 30,
2000 1999 2000 1999
------------ ------------ ------------ ------------
Segment earnings $ 111,243 $ 78,153 $ 317,999 $ 204,508
Interest and corporate
administrative expenses (a) (41,383) (25,600) (116,770) (67,773)
------------ ------------ ------------ ------------
Net Income $ 69,860 $ 52,553 $ 201,229 $ 136,735
============ ============ ============ ============
(a) Includes interest expense, general and administrative expenses, minority
interest and other insignificant items.
(2) The following reconciles segment assets to consolidated assets.
Sept. 30, Dec. 31,
2000 1999
------------ ------------
Segment assets $ 3,555,178 $ 3,185,356
Corporate assets (b) 52,177 43,382
------------ ------------
Total assets $ 3,607,355 $ 3,228,738
============ ============
(b) Includes cash, cash equivalents and certain unallocable deferred charges.
9. Subsequent Events
On October 4, 2000, we announced that KMI intends to contribute
approximately $300 million of assets to the Partnership. As consideration for
these assets, we will pay KMI approximately 50% of the fair value in cash and
the remaining 50% of fair value in units. We expect the transaction to be
consummated during the fourth quarter of 2000. The largest asset to be
contributed is Kinder Morgan Texas Pipeline, Inc., a 2,600-mile natural gas
pipeline system that extends from south Texas to Houston along the Texas Gulf
Coast. Other assets include the Casper and Douglas Natural Gas Gathering and
Processing Systems, KMI's 50% interest in Coyote Gas Treating, LLC and KMI's 25%
interest in Thunder Creek Gas Services, LLC.
On October 13, 2000, we announced that we signed a definitive agreement
with a subsidiary of Buckeye Partners, L.P. to purchase its transmix processing
plants in Indianola, Pennsylvania and Wood River, Illinois for approximately $37
million plus net working capital. The two facilities are projected to process
over 4.3 million barrels of transmix in 2000. The transaction was closed on
October 25, 2000.
On October 23, 2000, we announced that we agreed to purchase a 32.5%
interest in the Cochin Pipeline System from NOVA Chemicals Corporation. The
Cochin pipeline consists of approximately 1,900 miles of 12-inch pipeline
operating between Fort Saskatchewan, Alberta and Sarnia, Ontario. It transports
high vapor pressure ethane, ethylene, propane, butane and natural gas liquids to
the Midwestern United States and eastern Canadian petrochemical and fuel
markets, and is a joint venture of subsidiaries of BP Amoco, Conoco, Shell and
NOVA Chemicals. Our purchase is subject to rights of first refusal from the
other Cochin Pipeline owners, as well as regulatory approval.
Page 16 of 26
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Results of Operations
Third Quarter 2000 Compared With Third Quarter 1999
Our third quarter results continued to demonstrate strong revenue growth
as well as increased earnings across all of our business segments. For the
quarter ended September 30, 2000, our total earnings increased 33% (to $69.9
million or $0.67 per unit) and our total revenues increased 94% (to a record
$202.6 million) compared to the same period in 1999. We reported earnings of
$52.6 million on revenues of $104.4 million for the third quarter of 1999. The
1999 third quarter results included an extraordinary charge of $2.6 million
related to the write-off of unamortized debt issue costs, mainly associated with
the refinancing of our bank credit facility in September 1999. Income before the
extraordinary charge was $55.2 million ($0.82 per unit). The quarter-to-quarter
decrease in net income per unit was the result of a higher average number of
units outstanding. We acquired substantially all of our Natural Gas Pipelines
from Kinder Morgan, Inc. on December 31, 1999, for $330 million in cash and the
issuance of 9.81 million units. Related to our acquisition of the remaining 80%
ownership interest in Kinder Morgan CO2 Company, L.P. (formerly Shell CO2
Company, Ltd.) effective April 1, 2000, we issued an additional 4.5 million
units in a public offering. The 1999 third quarter results also included a
benefit of $10.1 million related to the sale of our interest in the Mont Belvieu
fractionation facility, partially offset by special non-recurring charges (see
Note 3 to the Consolidated Financial Statements). Our increases in overall
earnings and revenues primarily resulted from our inclusion of the Natural Gas
Pipelines, and our acquisition of the remaining 80% ownership interest in KMCO2.
Prior to that date, we owned a 20% equity interest in KMCO2 and reported its
results under the equity method of accounting. The results of KMCO2 are included
in our CO2 Pipelines business segment. Our acquisitions of the Product
Pipelines' transmix operations in September 1999, and Milwaukee Bulk Terminals,
Inc. and Dakota Bulk Terminal, Inc. in January 2000, also contributed to our
overall increase in period-to-period revenues and earnings. These acquisitions
increased our combined operating expenses, excluding depreciation, amortization,
and taxes, other than income taxes, to $80.9 million in the third quarter of
2000. We reported $31.9 million of operating expenses in the third quarter of
1999. Our total operating income for the third quarter of 2000 increased 64% (to
$79.8 million) compared to the $48.8 million in operating income for the third
quarter of 1999. Third quarter earnings from equity investments, net of
amortization of excess costs, were $18.4 million in 2000 and $12.0 million in
1999. The 53% increase ($6.4 million) in net equity earnings was mainly due to
earnings from our 49% interest in the Red Cedar Gathering Company, acquired from
KMI on December 31, 1999, and to earnings from our 50% interest in Cortez
Pipeline Company, which is owned by KMCO2. Due to our acquisition of the
remaining 80% interest in KMCO2 in April 2000, the earnings from our investment
in Cortez are now reported under the equity method of accounting. Our overall
increase in net equity earnings was partially offset by the absence of third
quarter 2000 equity earnings from our original 20% interest in KMCO2, because
the interest was no longer accounted for as an equity investment.
Product Pipelines
Our Product Pipelines' business segment revenues increased 23% (to $93.5
million) and earnings increased 4% (to $52.8 million) during the third quarter
of 2000 compared to the third quarter of 1999. For the third quarter of 1999,
the segment reported revenues of $76.3 million and earnings of $51.0 million.
Our $17.2 million increase in segment revenues was primarily due to the
inclusion of a full quarter of transmix operations and to a 4% increase in
revenues generated from our Pacific pipelines. Although tariff rates remained
relatively flat, an almost 3% increase in mainline delivery volumes contributed
to the Pacific pipelines' revenue growth. Segment operating expenses for the
third quarter of 2000 were $33.8 million, and segment operating income totaled
$46.0 million. These amounts compared to expenses of $15.8 million and operating
income of $47.6 million for the third quarter of 1999. Our higher segment
operating expenses were due to the inclusion of a full quarter of transmix
operations and the higher transportation volumes. Along with the transmix
expenses and the higher transportation volumes, segment operating income was
affected by higher depreciation and property tax charges, primarily due to
investments made to our Pacific pipelines since September 1999. Earnings from
the Product Pipelines' equity investments, net of amortization of excess costs,
increased to $9.7 million in the third quarter of 2000 versus $7.1 million in
the third quarter of 1999. The segment's $2.6 million increase in net equity
earnings was the result of higher income from our investment in Plantation Pipe
Line Company. Plantation realized an almost 8% increase in delivery volumes,
partially offset by a slight (2%) decrease in average tariff rates.
Page 17 of 26
Natural Gas Pipelines
Our Natural Gas Pipelines, acquired on December 31, 1999, reported
earnings of $29.6 million on revenues of $46.0 million during the third quarter
of 2000. Segment operating expenses totaled $15.6 million in the third quarter
of 2000 and segment operating income was $25.5 million. Third quarter 1999
segment income totaled $15.4 million, consisting of $1.3 million in equity
earnings from our partnership interest in the Mont Belvieu fractionation
facility and a $14.1 million gain on the sale of that interest to Enterprise
Products Partners, L.P. For the third quarter of 2000, we reported $3.8 million
in earnings from equity investments, net of amortization of excess costs. This
amount represents the net earnings from our 49% interest in Red Cedar.
CO2 Pipelines
Our CO2 Pipelines reported earnings of $19.8 million in the third quarter
of 2000 compared with earnings of $3.6 million in the same period last year. The
segment's 1999 net earnings represented equity earnings from our original 20%
interest in KMCO2. After our acquisition of the remaining 80% interest in KMCO2,
the financial results of KMCO2 were no longer reported under the equity method.
For the third quarter of 2000, the segment reported operating revenues of $30.0
million, operating expenses of $10.3 million and operating income of $14.9
million. The segment's equity earnings, net of amortization of excess costs,
were $4.9 million in the third quarter of 2000. The amount represented earnings
from our 50% interest in Cortez.
Bulk Terminals
Bulk Terminals reported an 18% increase (to $33.1 million) in operating
revenues and an 11% increase (to $9.0 million) in earnings for the third quarter
of 2000 when compared with the third quarter of 1999. For last year's third
quarter, our Bulk Terminals segment reported earnings of $8.1 million on
revenues of $28.1 million. Combined operating expenses totaled $21.3 million in
the third quarter of 2000 versus $16.1 million in the third quarter of 1999. We
attribute the increases in revenues and expenses mainly to terminal acquisitions
that we made after the third quarter of 1999. Including the new businesses, our
Bulk Terminals segment reported a 9% increase in average transfer rates,
accompanied by an almost 3% increase in volumes transferred. Operating income
for the segment was $8.5 million in the third quarter of 2000 versus $9.1
million for the same quarter last year. Our acquisitions and capital
improvements made during 2000 contributed to increases in both operating and
depreciation expenses.
Operating statistics for the third quarter of 2000 and 1999 are as follows:
Three Months Ended Sept. 30,
2000 1999
---------------
Product Pipelines
Pacific - Mainline Delivery Volumes (MMBbls) 99.9 97.3
- Other Delivery Volumes (MMBbls) 3.5 2.3
Plantation - Delivery Volumes (MMBbls) 57.2 53.1
North System/Cypress - Delivery Volumes (MMBbls) 11.3 11.8
Natural Gas Pipelines
Transport Volumes (Bcf)* 118.7 110.9
CO2 Pipelines
Delivery Volumes (Bcf)** 96.1 92.8
Bulk Terminals
Transload Tonnage (MM Tons) 10.0 9.7
- --------------------------------------------------------------------------------
* KMIGT and Trailblazer assets acquired December 31, 1999. 1999 volumes shown
for comparative purposes only.
** Additional 80% KMCO2 interest acquired, effective April 1, 2000. 1999 volumes
shown for comparative purposes only.
Items not attributable to any segment include general and administrative
expenses, interest income and
Page 18 of 26
expense and minority interest. General and administrative expenses were $15.1
million in the third quarter of 2000 compared with $7.9 million in the same
period last year. The increase was principally associated with assets acquired
from KMI on December 31, 1999. Interest expense, net of interest income, was
$24.1 million in the third quarter of 2000 compared with $14.2 million in the
same year-earlier period. The increase was due to higher average debt balances
and higher average borrowing rates. Minority interest was $2.2 million for the
third quarter of 2000 versus $0.9 million in the third quarter of the prior
year. The increase reflects the 33 1/3% minority interest in Trailblazer as well
as our higher overall net income.
We reported an increase in income tax expense of $0.9 million in the third
quarter of 2000 compared to last year's third quarter. The increase represented
our higher share of income tax expense from our investment in Plantation. The
higher taxes corresponded with the increase in equity earnings from our
investment.
Nine Months Ended September 30, 2000 Compared With Nine Months Ended
September 30, 1999
Beginning with the first quarter of 2000, our results reflect key
acquisitions and changes made within our business segments. Specifically, the
acquisition of our Natural Gas Pipelines from KMI on December 31, 1999 and the
acquisition of the remaining 80% interest of KMCO2 on April 1, 2000, have
significantly increased our revenues and expenses and resulted in substantial
increases in our operating income. Net earnings for the nine months ended
September 30, 2000 were $201.2 million ($2.00 per unit) compared with net
earnings of $136.7 million ($1.95 per unit) for the first nine months of 1999.
Included in the net earnings for 1999 was an extraordinary charge of $2.6
million related to the write-off of unamortized debt issue costs. Income before
the extraordinary charge was $139.3 million ($2.00 per unit). We reported total
revenues of $553.7 million for the first nine months of 2000 compared to $307.4
million for the same period of 1999. The 80% increase in revenues and the 44%
increase in earnings before extraordinary charges were distributed across all
four of our business segments. Operating expenses were $208.0 million for the
nine-month period ended September 30, 2000 and $91.8 million for the nine-month
period ended September 30, 1999. Operating income was $222.9 million for the
nine months ended September 30, 2000. This amount represents a 55% increase over
the $143.8 million in operating income reported for the same prior year period.
Equity earnings from investments, less amortization of excess costs, were $46.7
million in the first nine months of 2000 compared to $28.3 million in the first
nine months of 1999. The increase of $18.4 million was primarily due to our
acquisition of a 49% equity interest in Red Cedar in December 1999, our
additional 27% equity investment in Plantation made in June 1999, and the
inclusion of earnings from our investment in Cortez. Our overall increase in net
equity earnings was offset by the reduction in equity earnings from our 20%
interest in KMCO2 as a result of our acquisition of the remaining 80% of KMCO2
on April 1, 2000, and by the absence of earnings from our investment in the Mont
Belvieu fractionation facility, which we sold in the third quarter of 1999.
Product Pipelines
Our Product Pipelines' segment reported earnings of $159.8 million on
revenues of $274.8 million for the first nine months of 2000. These amounts
compared with earnings of $149.8 million on revenues of $221.0 million for the
same period of 1999. Segment operating expenses totaled $98.2 million for the
nine months ended September 30, 2000, and $42.8 million for the nine-month
period ended September 30, 1999. The increases in revenues and operating
expenses resulted primarily from the inclusion of our transmix operations,
acquired in September 1999. Additionally, higher throughput volumes on both our
Pacific and North System pipelines contributed to the increases in segment
revenues and operating expenses. The Pacific pipelines reported an almost 4%
increase in mainline delivery volumes and the North System reported an almost 6%
increase in throughput volumes. The Pacific pipelines also reported a 4%
increase in fuel and power expenses and a slight (1%) decrease in average tariff
rates due to the reduction in transportation rates, effective April 1, 1999, on
the pipeline's East Line. Net operating income for the Product Pipelines segment
was $135.5 million for the first nine months of 2000 and $139.7 million for the
comparable period of 1999. Segment net operating income was impacted by higher
depreciation charges and higher tax expense on the Pacific pipelines, due to
capital investments made since the third quarter of 1999. The segment's earnings
from equity investments, net of amortization of excess costs, increased to $22.7
million in the nine-month period of 2000 versus $14.9 million in the same period
last year. The $7.8 million increase in the segment's net equity earnings was
mainly the result of higher income from our having a 51% ownership interest in
Plantation for the entire nine-month period ended September 30, 2000.
Natural Gas Pipelines
Our Natural Gas Pipelines segment reported earnings of $85.2 million on
revenues of $126.1 million for the
Page 19 of 26
first nine months of 2000. The operations of our Natural Gas Pipelines,
excluding our former equity investment in the Mont Belvieu fractionation
facility and our 33 1/3% interest in Trailblazer, were acquired on December 31,
1999. We sold our partnership interest in the Mont Belvieu fractionation
facility in the third quarter of 1999 and acquired our initial one-third
interest in Trailblazer on November 30, 1999. For the nine-month period ended
September 30, 2000, segment operating expenses were $33.6 million and segment
operating income was $73.6 million. For the same period last year, the segment
reported earnings of $16.6 million, consisting of the $14.1 million gain on the
sale of our interest in the Mont Belvieu fractionation facility and $2.5 million
in equity earnings. Equity earnings, net of amortization of excess costs, were
$11.2 million in the first nine months of 2000. The $8.7 million year-to-year
increase represents the difference between the 2000 earnings from our 49%
interest in Red Cedar and the 1999 earnings from our former equity interest in
the Mont Belvieu fractionation facility.
CO2 Pipelines
Our CO2 Pipelines activities consist of KMCO2. Prior to April 1, 2000, we
owned a 20% equity interest in KMCO2 and reported its results under the equity
method of accounting. As a result of acquiring the remaining 80% interest in
KMCO2, we commenced consolidating the financial results of KMCO2 on a current
basis. Our CO2 Pipelines segment reported earnings of $44.0 million on revenues
of $54.6 million for the first nine months of 2000. For the same period, the
segment reported operating expenses of $16.1 million and operating income of
$30.5 million. Equity earnings, net of amortization of excess costs, were $12.8
million in the first nine months of 2000. Equity earnings, net of amortization
of excess costs, were $10.9 million in the first nine months of last year. The
$1.9 million increase reflects the $9.2 million in earnings from Cortez, offset
by a $7.3 million decrease in earnings from our equity interest in KMCO2.
Bulk Terminals
For the comparative nine-month periods, our Bulk Terminals segment
reported a 6% increase in segment earnings and a 14% increase in total revenues.
The segment earned $29.0 million on revenues of $98.2 million during the first
nine months of 2000, compared with earnings of $27.3 million on revenues of
$86.4 million during the same period last year. The current year amounts
included the operations of Milwaukee Bulk Terminals, Inc. and Dakota Bulk
Terminal, Inc., both acquired on January 1, 2000. Our $11.8 million increase in
segment revenues reflected an almost 6% increase in total coal and bulk tonnage
volumes transferred, as well as a 4% increase in average transfer rates. Our
terminal acquisitions and the resulting overall increase in transferred volumes
resulted in higher segment operating expenses. For the nine-month period ended
September 30, 2000, Bulk Terminals reported operating expenses of $60.1 million
and operating income of $28.0 million. For the same period in 1999, our Bulk
Terminals segment reported operating expenses of $49.0 million and operating
income of $28.9 million.
Operating statistics for the first nine months of 2000 and 1999 are as follows:
Page 20 of 26
Nine Months Ended Sept. 30,
2000 1999
---------------
Product Pipelines
Pacific - Mainline Delivery Volumes (MMBbls) 288.4 278.4
- Other Delivery Volumes (MMBbls) 10.3 7.3
Plantation - Delivery Volumes (MMBbls) 166.2 162.6
North System/Cypress - Delivery Volumes (MMBbls) 36.1 35.5
Natural Gas Pipelines
Transport Volumes (Bcf)* 339.3 324.0
CO2 Pipelines
Delivery Volumes (Bcf)** 384.0 358.8
Bulk Terminals
Transload Tonnage (MM Tons) 31.2 29.5
- --------------------------------------------------------------------------------
* KMIGT and Trailblazer assets acquired December 31, 1999. 1999 volumes shown
for comparative purpose only.
** Additional 80% KMCO2 interest acquired, effective April 1, 2000. Year-to-date
2000 and 1999 volumes shown for comparative purposes only, and adjusted to
include properties acquired from Devon Energy effective June 1, 2000.
Items not attributable to any segment include general and administrative
expenses, interest income and expense and minority interest. General and
administrative expenses were $44.8 million in the nine-month period ended
September 30, 2000 and $24.7 million in the nine-month period ended September
30, 1999. The increase in general and administrative expenses over last year was
due to our larger and more diverse operations. Interest expense, net of interest
income, was $66.0 million in the first nine months of 2000 compared with $38.2
million in the same period last year. The increase was due to higher average
debt balances and higher average borrowing rates. Minority interest, which
includes all subsidiary partners other than us, amounted to $6.0 million for the
nine months ended September 30, 2000 and $2.3 million for the nine months ended
September 30, 1999. The increase reflected the 33 1/3% minority interest in
Trailblazer and our higher overall net income.
We reported an increase in income tax expense of $3.4 million in the first
nine months of 2000 compared to the first nine months of last year. The increase
was principally due to our higher share of income tax expense from our
investment in Plantation.
Financial Condition
Our primary cash requirements, in addition to normal operating expenses,
are debt service, sustaining capital expenditures, expansion capital
expenditures and quarterly distributions to partners. In addition to utilizing
cash generated from operations, we could meet our cash requirements through
borrowings under our credit facilities or issuing short-term commercial paper,
long-term notes or additional units. We expect to fund:
o future cash distributions and sustaining capital expenditures with existing
cash and cash flows from operating activities;
o expansion capital expenditures through additional borrowings or issuance of
additional units;
o interest payments from cash flows from operating activities; and
o debt principal payments with additional borrowings as they become due or by
issuance of additional units.
Operating Activities
Net cash provided by operating activities was $192.8 million for the nine
months ended September 30, 2000, versus $144.8 million in the comparable period
of 1999. The period-to-period increase in cash flow from operations was
primarily the result of:
o a $61.9 million increase in net earnings;
o a $25.2 million increase in non-cash depreciation and amortization
charges;
o an $11.0 million increase in distributions from equity investments;
o a $10.1 million gain on the sale of our equity interest in the Mont Belvieu
fractionation facility, net of special charges, in the third quarter of 1999;
and
Page 21 of 26
o an $8.6 million increase in cash inflows related to our Pacific pipelines'
insurance receivables.
The higher earnings and non-cash depreciation charges in the first nine
months of 2000 compared to the prior year were primarily due to the business
acquisitions and capital investments we have made since September 1999. The
increase in distributions from equity investments reflected returns from our
equity interest in Cortez, accounted for under the equity method following our
acquisition of the remaining interest in KMCO2, and returns from our additional
interest in Plantation, acquired in June 1999. The overall increase in cash
provided by operating activities was partially offset by:
o a $47.9 million payment of accrued rate refund liabilities;
o an $18.5 million increase in undistributed earnings from equity investments,
including amortization of excess costs; and
o a $4.3 million decrease in cash inflows relative to net changes in working
capital items.
The payment of the rate refunds was made under settlement agreements with
shippers on our Natural Gas Pipelines. The increase in undistributed earnings
from equity investments resulted primarily from income generated from our
December 1999 investment in Red Cedar and our April 2000 investment in Cortez.
The absence of earnings from January 1, 2000 through September 30, 2000, from
our investment in the Mont Belvieu fractionation facility, and from April 1,
2000 through September 30, 2000, from our investment in KMCO2, offset higher
overall earnings from equity investments. We sold our interest in the
fractionation facility in the third quarter of 1999, and as a result of
acquiring the remaining 80% interest in KMCO2 on April 1, 2000, we no longer
accounted for our investment in KMCO2 on an equity basis.
Investing Activities
Net cash used in investing activities was $647.0 million for the
nine-month period ended September 30, 2000, compared to $157.8 million in the
comparable 1999 period. The $489.2 million increase in funds utilized in
investing activities was mainly attributable to the $573.4 million of asset
acquisitions that we made in the first nine months of 2000. The acquisition
outlays primarily consisted of:
o a $330.0 million payment to KMI for the Natural Gas Pipelines;
o a net payment of $188.9 million for the remaining 80% interest in KMCO2;
and
o a $53.4 million payment for our interests in the Canyon Reef Carriers CO2
pipeline and SACROC Unit.
The overall increase in funds used in investing activities was offset by
our $124.2 million investment in Plantation in June 1999. Cash used for capital
expenditures increased $20.2 million (to $81.9 million) in the first nine months
of 2000 versus the same period last year. The increase primarily reflected
higher investments made in our Bulk Terminals and Product Pipelines business
segments. All funds classified as additions to property, plant and equipment
included both expansion and sustaining capital expenditures.
Financing Activities
Net cash provided by financing activities amounted to $451.7 million for
the nine months ended September 30, 2000. This increase of $440.7 million from
the comparable 1999 period was mainly the result of an additional $329.7 million
received from overall debt financing activities. We completed a private
placement of $400 million in debt securities during the first quarter of 2000,
resulting in a cash inflow of $397.9 million net of discounts and issuing costs.
In addition, we received $171.4 million as proceeds from the issuance of units
during the nine-month period ended September 30, 2000. Most of these funds were
realized from our 4,500,000-unit public offering on April 4, 2000. The general
increase in funds provided by financing activities was partially offset by a
$70.6 million increase in distributions to partners in the 2000 period.
Distributions to all partners increased to $210.2 million in the
nine-month period ended September 30, 2000, compared to $139.6 million in the
corresponding 1999 period. The increase in distributions was due to:
o an increase in the per unit distributions paid;
o an increase in the number of units outstanding; and
o the general partner incentive distributions, which resulted from increased
distributions to unitholders.
Page 22 of 26
We paid distributions of $2.35 per unit in the first nine months of 2000
compared with distributions of $2.05 per unit in the first nine months of 1999.
The 15% increase in paid distributions per unit resulted from favorable
operating results in 2000. On October 19, 2000, we declared a distribution of
$0.85 per unit for the third quarter of 2000. We believe that future operating
results will continue to support similar levels of quarterly cash distributions,
however, no assurance can be given that future distributions will continue at
such levels.
Our partnership agreement requires that we distribute 100% of "Available
Cash" (as defined in the 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 in respect of its remaining 0.5%
interest in SFPP.
Available Cash is initially distributed 98% to our limited partners
(including the approximate 2% limited partner interest owned by our general
partner) 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 our limited partners and 2% to our general partner until our
limited partners have received a total of $0.3025 per unit for such quarter;
o second, 85% to our limited partners and 15% to our general partner until our
limited partners have received a total of $0.3575 per unit for such quarter;
o third, 75% to our limited partners and 25% to our general partner until our
limited partners have received a total of $0.4675 per unit for such quarter;
and
o fourth, thereafter 50% to our limited partners 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 amount of
cash being distributed. The general partner's incentive distribution that we
declared for the third quarter of 2000 was $26.6 million, while the incentive
distribution paid to our general partner was $62.8 million during the first nine
months of 2000 and $36.9 million during the first nine months of 1999.
Information Regarding Forward Looking Statements
This filing includes forward looking statements within the meaning of
Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. 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," "continue," "estimate," "expect," "may," "will," or
other similar words. These statements discuss future expectations or contain
projections. 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, carbon dioxide, natural gas, coal and other bulk materials 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 if railroads experience difficulties or delays in delivering products to
the bulk terminals;
o our ability to successfully identify and close strategic acquisitions
and make cost saving changes in operations;
o shut-downs or cutbacks at major refineries, petrochemical plants, utilities,
military bases or other businesses that use our services;
o the condition of the capital markets and equity markets in the United
States; and
o the political and economic stability of the oil producing nations of the
world.
Page 23 of 26
See Items 1 and 2 "Business and Properties - Risk Factors" of the Annual
Report filed on Form 10-K with the Securities and Exchange Commission on March
14, 2000 for a more detailed description of these and other factors that may
affect the forward looking statements. When considering forward looking
statements, you should keep in mind the risk factors described in the Form 10-K.
The risk factors could cause our actual results to differ materially from those
contained in any forward looking statement. We disclaim any obligation to update
the above list or to announce publicly the result of any revisions to any of the
forward looking statements to reflect future events or developments.
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,
1999, in Item 7a of our 1999 Form 10-K.
Page 24 of 26
PART II. OTHER INFORMATION
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
ITEM 1. Legal Proceedings
See Part I, Item 1, Note 4 to Consolidated Financial Statements
entitled "Litigation and Other Contingencies" which is incorporated
herein by reference.
ITEM 2. Changes in Securities and Use of Proceeds
During the quarter ended September 30, 2000, we did not issue any
securities that were not registered under the Securities Act of 1933,
as amended.
ITEM 3. Defaults Upon Senior Securities
None.
ITEM 4. Submission of Matters to a Vote of Security Holders
None.
ITEM 5. Other Information
None.
ITEM 6. Exhibits and Reports on Form 8-K
(a) Exhibits
4.1 - Certain instruments with respect to our long-term debt which relate to
debt that does not exceed 10% of our total assets are omitted pursuant
to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R. ss.229.601. We
hereby agree to furnish supplementally to the Securities and Exchange
Commission a copy of each such instrument upon request.
*27.1 - Financial Data Schedule for Kinder Morgan Energy Partners, L.P.
---------------------
* Filed herewith.
(b) Reports on Form 8-K.
None.
Page 25 of 26
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.
as General Partner
By: /s/ C. Park Shaper
------------------------------
C. Park Shaper
Vice President, Treasurer
and Chief Financial Officer
Date: November 8, 2000