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 June 30, 2001
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
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(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 64,882,709 common units outstanding at August 3, 2001.
Page 1 of 38
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 Six Months
Ended June 30, 2001 and 2000 3
Consolidated Balance Sheets - June 30, 2001 and
December 31, 2000 4
Consolidated Statements of Cash Flows - Six Months
Ended June 30, 2001 and 2000 5
Notes to Consolidated Financial Statements 6
Item 2. - Management's Discussion and Analysis of
Financial Condition and Results of Operations 25
Item 3. - Quantitative and Qualitative Disclosures about
Market Risk 33
PART II. OTHER INFORMATION
Item 1. - Legal Proceedings 34
Item 2. - Changes in Securities and Use of Proceeds 34
Item 3. - Defaults Upon Senior Securities 35
Item 4. - Submission of Matters to a Vote of Security Holders 35
Item 5. - Other Information 35
Item 6. - Exhibits and Reports on Form 8-K 35
Page 2 of 38
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 June 30, Six Months Ended June 30,
2001 2000 2001 2000
-------------- ------------- -------------- -------------
Revenues $ 735,755 $ 193,758 $ 1,764,400 $ 351,116
Costs and Expenses
Operations and maintenance 527,731 72,022 1,345,692 127,054
Depreciation, depletion and amortization 35,948 19,904 66,023 38,749
General and administrative 18,016 15,380 46,601 29,703
Taxes, other than income taxes 15,464 6,476 29,137 12,573
-------------- ------------- -------------- -------------
597,159 113,782 1,487,453 208,079
-------------- ------------- -------------- -------------
Operating Income 138,596 79,976 276,947 143,037
Other Income (Expense)
Earnings from equity investments 21,147 17,362 42,350 32,179
Amortization of excess cost of equity investments (2,253) (2,174) (4,506) (3,847)
Interest, net (45,275) (21,797) (95,082) (41,915)
Other, net (677) 3,832 (403) 11,743
Minority Interest (2,633) (2,091) (5,635) (3,769)
-------------- ------------- -------------- -------------
Income Before Income Taxes 108,905 75,108 213,671 137,428
Income Taxes (4,679) (3,298) (7,778) (6,059)
-------------- ------------- -------------- -------------
Net Income $ 104,226 $ 71,810 $ 205,893 $ 131,369
============== ============= ============== =============
General Partner's interest in Net Income $ 50,606 $ 27,003 $ 92,228 $ 49,260
Limited Partners' interest in Net Income 53,620 44,807 113,665 82,109
-------------- ------------- -------------- -------------
Net Income $ 104,226 $ 71,810 $ 205,893 $ 131,369
============== ============= ============== =============
Basic and Diluted Net Income per Unit $ 0.72 $ 0.70 $ 1.60 $ 1.33
============== ============= ============== =============
Weighted Average Number of Units used in Computation of Net Income per Unit
Basic 74,741 64,064 71,150 61,787
Diluted 74,843 64,088 71,246 61,818
Additional per Unit information
Declared distribution $ 1.05 $ 0.85 $ 2.10 $ 1.63
============== ============= ============== =============
The accompanying notes are an integral part of these consolidated financial statements.
Page 3 of 38
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands)
(Unaudited)
June 30, December 31,
2001 2000
------------- -------------
ASSETS
Current Assets
Cash and cash equivalents $ 116,441 $ 59,319
Accounts and notes receivable
Trade 293,405 345,065
Related parties 50,731 3,384
Inventories
Products 2,699 24,137
Materials and supplies 5,780 4,972
Gas imbalances 13,188 26,878
Gas in underground storage 36,799 27,481
Other Current Assets 47,877 20,025
------------- -------------
566,920 511,261
------------- -------------
Property, Plant and Equipment, net 4,328,006 3,306,305
Investments 445,767 417,045
Notes receivable
Trade 8,061 9,101
Related parties 17,100 -
Intangibles, net 641,349 345,305
Deferred charges and other assets 254,476 36,193
------------- -------------
TOTAL ASSETS $ 6,261,679 $ 4,625,210
============= =============
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Accounts payable
Trade $ 191,078 $ 293,268
Related parties 43,949 8,255
Current portion of long-term debt - 648,949
Deferred revenues 4,420 43,978
Gas imbalances 39,538 48,834
Accrued other liabilities 131,793 55,672
------------- -------------
410,778 1,098,956
------------- -------------
Long-Term Liabilities and Deferred Credits
Long-term debt 2,195,933 1,255,453
Deferred revenues 21,848 1,503
Other 460,076 94,062
------------- -------------
2,677,857 1,351,018
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Commitments and Contingencies
Minority Interest 66,255 58,169
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Partners' Capital
Common Units 1,932,330 1,957,357
Class B Units 127,401 125,961
i-Units 1,002,055 -
General Partner 50,833 33,749
Accumulated other comprehensive income (5,830) -
------------- -------------
3,106,789 2,117,067
------------- -------------
TOTAL LIABILITIES AND PARTNERS' CAPITAL $ 6,261,679 $ 4,625,210
============= ============
The accompanying notes are an integral part of these consolidated financial
statements.
Page 4 of 38
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)
Six Months Ended June 30,
2001 2000
------------------- -------------------
Cash Flows From Operating Activities
Reconciliation of net income to net cash provided by operating activities
Net income $ 205,893 $ 131,369
Depreciation and amortization 66,023 38,749
Amortization of excess cost of equity investments 4,506 3,847
Earnings from equity investments (42,350) (32,179)
Distributions from equity investments 29,544 24,971
Changes in components of working capital (36,094) (17,240)
Rate refunds settlement - (47,706)
Other, net 54,519 2,743
------------------- -------------------
Net Cash Provided by Operating Activities 282,041 104,554
------------------- -------------------
Cash Flows From Investing Activities
Acquisitions of assets (1,028,403) (572,488)
Additions to property, plant and equipment (109,190) (52,599)
Sale of investments, property, plant and equipment, net of removal costs 5,711 8,539
Contributions to equity investments (1,899) (229)
Other (5,844) 568
------------------- -------------------
Net Cash Used in Investing Activities (1,139,625) (616,209)
------------------- -------------------
Cash Flows From Financing Activities
Issuance of debt 3,209,734 1,087,786
Payment of debt (3,053,184) (633,996)
Loans to related party (17,100) -
Debt issue costs (7,953) (1,912)
Proceeds from issuance of common units 833 171,298
Proceeds from issuance of i-units 996,869 -
Contributions from General Partner's Minority Interest - 7,434
Distributions to partners
Common Units (129,128) (85,527)
Class B Units (2,790) -
General Partner (75,134) (37,161)
Minority Interest (7,662) (4,011)
Other, net 221 659
------------------- -------------------
Net Cash Provided by (Used in) Financing Activities 914,706 504,570
------------------- -------------------
Increase in Cash and Cash Equivalents 57,122 (7,085)
Cash and Cash Equivalents, Beginning of Period 59,319 40,052
------------------- -------------------
Cash and Cash Equivalents, End of Period $ 116,441 $ 32,967
=================== ===================
Noncash Investing and Financing Activities
Assets acquired by the issuance of Common Units $ - $ 23,319
Assets acquired by the assumption of liabilities 257,304 41,342
The accompanying notes are an integral part of these consolidated financial statements.
Page 5 of 38
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 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, as amended, for the year ended December 31, 2000.
On May 14, 2001, Kinder Morgan Management, LLC, a wholly-owned subsidiary of
our general partner, filed a registration statement with the Securities and
Exchange Commission with respect to an initial public offering of 14,875,000 of
its shares representing limited liability company interests with limited voting
rights. Kinder Morgan Management, LLC trades on the New York Stock Exchange
under the symbol "KMR" and is referred to as "KMR" in this report. On May 17,
2001, KMR issued 1,487,500 shares to Kinder Morgan, Inc. and on May 18, 2001, it
issued 13,387,500 shares to the public. Its shares were issued at a price of
$70.41 per share, less commissions and underwriting expenses. Substantially all
of the net proceeds from the offering were used to buy i-units from us. The
i-units are a new and separate class of limited partner interests in us and are
issued only to KMR. Upon purchasing the i-units, KMR became a limited partner in
the Partnership, and in accordance with its limited liability company agreement,
its activities will be restricted to being a limited partner in, and controlling
and managing the business and affairs of the Partnership, our operating
partnerships and our subsidiaries. See note 6 for more information.
We compute Basic Limited Partners' Net Income per Unit by dividing 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 six months of 2001, we completed the following significant
acquisitions. Each of the acquisitions was accounted for under the purchase
method of accounting and the assets and liabilities assumed were recorded at
their estimated fair market values as of the acquisition date. The results of
operations from these acquisitions are included in the consolidated financial
statements from the date of acquisition.
Product Pipelines
Central Florida Pipeline LLC
Effective January 1, 2001, we acquired Central Florida Pipeline LLC (formerly
Central Florida Pipeline Company) from GATX Corporation. Central Florida
Pipeline consists of a 195-mile pipeline transporting refined petroleum products
from Tampa to the growing Orlando, Florida market. Our purchase price was
approximately $212.5 million, consisting of $168.2 million in cash, $40 million
in assumed debt and $4.3 million in assumed liabilities.
Page 6 of 38
Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $ 168,211
Debt assumed 40,000
Liabilities assumed 4,318
-----------
Total purchase price $ 212,529
===========
Allocation of purchase price:
Current assets $ 4,500
Property, plant and equipment 128,373
Deferred charges and other assets 233
Goodwill 79,423
-----------
$ 212,529
===========
CALNEV Pipe Line LLC
Effective March 30, 2001, we acquired CALNEV Pipe Line LLC (formerly CALNEV
Pipe Line Company) from GATX Corporation. CALNEV Pipe Line consists of a
550-mile refined petroleum products pipeline originating in Colton, California
and extending into the growing Las Vegas, Nevada market. The pipeline
interconnects in Colton with our Pacific Operations' West Line pipeline segment.
Our purchase price was approximately $370.2 million, consisting of $352.1
million in cash, $6.8 million in assumed debt and $11.3 million in assumed
liabilities.
Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $ 352,118
Debt assumed 6,816
Liabilities assumed 11,290
-----------
Total purchase price $ 370,224
===========
Allocation of purchase price:
Current assets $ 6,476
Property, plant and equipment 175,905
Deferred charges and other assets 148
Goodwill 187,695
-----------
$ 370,224
===========
Cochin Pipeline
On June 20, 2001, we acquired an additional 2.3% ownership interest in the
Cochin Pipeline System from Shell Canada Limited for approximately $8.0 million.
We now own approximately 34.8% of the Cochin Pipeline System and the remaining
interests are owned by subsidiaries of BP Amoco, Conoco and NOVA Chemicals. We
record our proportional share of joint venture revenues and expenses and cost of
joint venture assets as part of our Product Pipelines business segment. We
allocated our purchase price for the additional interest to property, plant and
equipment.
Bulk Terminals
Pinney Dock & Transport Company
Effective March 1, 2001, we acquired all of the shares of the capital stock
of Pinney Dock & Transport Company for $42.6 million. The acquisition includes a
bulk product terminal located in Ashtabula, Ohio on Lake Erie. The facility
handles iron ore, titanium ore, magnetite and other aggregates. Our purchase
price consisted of $41.5 million in cash and $1.1 million in assumed
liabilities.
Page 7 of 38
Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $ 41,494
Liabilities assumed 1,122
-----------
Total purchase price $ 42,616
===========
Allocation of purchase price:
Current assets $ 1,970
Property, plant and equipment 32,467
Deferred charges and other assets 487
Goodwill 7,692
-----------
$ 42,616
===========
Liquids Terminals
Kinder Morgan Liquids Terminals LLC
Effective January 1, 2001, we acquired Kinder Morgan Liquids Terminals LLC
(formerly GATX Terminals Corporation) from GATX Corporation. Acquired assets
included 12 terminals, located across the United States, which store
approximately 35.6 million barrels of refined petroleum products and chemicals.
Five of the terminals are included in our Liquids Terminals business segment,
and the remaining assets are included in our Products Pipelines business
segment. Our purchase price was $648.9 million, consisting of $455.1 million in
cash, $87.9 million in assumed debt and $105.9 million in assumed liabilities.
Our purchase price and the allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $ 455,099
Debt assumed 87,930
Liabilities assumed 105,828
-----------
Total purchase price $ 648,857
===========
Allocation of purchase price:
Current assets $ 21,388
Property, plant and equipment 623,066
Deferred charges and other assets 4,403
-----------
$ 648,857
===========
Pro Forma Information
The following summarized unaudited Pro Forma Consolidated Income Statement
information for the six months ended June 30, 2001 and 2000, assumes all of the
acquisitions we have made since January 1, 2000, including the ones above, had
occurred as of January 1, 2000. 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, 2000 or the results that
will be attained in the future. Amounts presented below are in thousands, except
for the per unit amounts:
Pro Forma
Six Months Ended
June 30, 2001 June 30, 2000
------------- -------------
Consolidated Income Statement (Unaudited)
Revenues $ 1,776,231 $ 1,590,023
Operating Income 281,651 244,242
Net Income 233,965 222,809
Basic Limited Partners' Net
Income per unit $ 1.61 $ 1.67
Diluted Limited Partners'
Net Income per unit $ 1.61 $ 1.67
Page 8 of 38
3. Litigation and Other Contingencies
Federal Energy Regulatory Commission Proceedings
SFPP, L.P.
SFPP, L.P. is the partnership that owns our Pacific operations. Tariffs
charged by SFPP are subject to certain proceedings 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. 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;
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
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
Page 9 of 38
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. Additional petitions for
review were thereafter filed in that court by RHC, Navajo, Chevron and SFPP.
SFPP and certain complainants each sought rehearing of Opinion No. 435 by
the FERC, asking that a number of rulings be modified. 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.
On July 6, 1999, in response to a motion by the FERC, the Court of Appeals
held the ARCO and RHC petitions in abeyance pending FERC action on petitions for
rehearing of Opinion No. 435 and dismissed the Navajo, Chevron and SFPP
petitions as premature because those parties had sought FERC rehearing.
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.
Page 10 of 38
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
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, and the court in an order issued January 19, 2001 denied a
November 2, 2000 motion by Chevron for reconsideration of that dismissal. 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.
Pursuant to the Court's orders, the FERC has filed quarterly reports
regarding the status of the proceedings pending before the Commission. On May
14, 2001, ARCO filed an Answer and Protest to the FERC's May 4, 2001 status
report, requesting the Court of Appeals to reactivate the petitions for review
that are being held in abeyance and to initiate a briefing schedule. On May 24,
2001, the FERC filed an opposition to that motion.
On July 6, 2001, ARCO, Chevron, Mobil, Navajo, RHC and Texaco filed a joint
motion asking the FERC to expedite its action on their requests for rehearing,
correction and clarification of Opinion No. 435-A and on SFPP's compliance
filing and related protests. On July 30, 2001, the Court of Appeals issued an
order denying ARCO's motion without prejudice and directing the FERC to advise
the Court in its next status report as to when the FERC expects to take final
action with respect to the proceedings on rehearing. On August 2, 2001, the FERC
filed a status report advising the Court that its current intent is to present
the pending requests for rehearing of Opinion No. 435-A for consideration at the
FERC's meeting scheduled for September 12, 2001.
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
Page 11 of 38
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.
On December 21, 2000, the FERC administrative law judge issued his initial
decision finding that SFPP possesses market power over the Sepulveda Lines
origin market. SFPP and other parties have filed briefs opposing and supporting
the initial decision with the FERC. The ultimate disposition of SFPP's market
rate 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 Lines. SFPP
sought clarification from FERC on the proper disposition of that issue in light
of the pendency of its market rate application and prior deferral of
consideration of SFPP's tariff filing. On February 22, 2001, the FERC granted
SFPP's motion and deferred consideration of the pending complaints against the
Sepulveda Lines rate until after its final disposition of SFPP's market rate
application.
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 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 FERC 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.
A hearing in this new proceeding is scheduled for October 2001. An initial
decision by the administrative law judge is expected in the first half of 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
Page 12 of 38
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.
On July 10, 2001, Ultramar filed a motion asking the FERC to expedite its
action on Ultramar's protest and intervention relating to SFPP's compliance
filing.
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 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.
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 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. On June 1, 2001,
CALNEV filed to adjust its interstate rates upward pursuant to the FERC's
indexing regulations. ARCO, Exxon Mobil, Ultramar Diamond Shamrock and Ultramar,
Inc. protested this adjustment. On June 29, 2001, the FERC accepted and
suspended the rate adjustment and permitted it to go into effect subject to
refund. The FERC withheld ruling on the protests pending submission by CALNEV of
its FERC Form No. 6 annual report and responses from the complainants to data
contained therein.
If an investigation into the basis for the indexing adjustment is ordered,
CALNEV's adjustment could be rejected and refunds ordered for amounts collected
under the suspended rates. CALNEV intends to contest vigorously any challenge to
its indexing adjustment.
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.
Page 13 of 38
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 six
months.
We believe that the resolution of such matters will not have a material
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 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.
FERC Order 637
On June 15, 2000, KMIGT made its filing to comply with the FERC's Orders 637
and 637-A. That filing contained KMIGT's compliance plan to implement the
changes required by the FERC dealing with the way business is conducted on
interstate pipelines. All interstate pipelines were required to make such
compliance filings, according to a schedule established by the 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 the comments received from FERC Staff and other
interested parties and shippers. On June 19, 2001, KMIGT received a letter from
the 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 filing contained little substantive change from the original
pro-forma tariff sheets that KMIGT originally proposed on June 15, 2000. KMIGT's
filing is currently pending FERC action, and any changes to its tariff
provisions are not likely to take effect until after the winter heating season
of 2001-2002. KMIGT expects no adverse impact on its business as a result of the
implementation of Order 637.
Separately, numerous petitioners, including KMIGT, have filed appeals of
Order No. 637 in the D.C. Circuit, potentially raising a wide array of issues.
Initial briefs were filed April 6, 2001, addressing a wide array of issues. Oral
argument on the appeals is set for November 2001.
Carbon Dioxide Litigation
Kinder Morgan CO2Company, L.P. directly and 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 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.);
Rutter & Wilbanks et al. v. Shell Oil Co., et al., No. 00-Z-1854 (U.S.D.C.
Colo.); Watson v. Shell Oil Co., et al., No. 00-Z-1855 (U.S.D.C. Colo.);
Ainsworth et al. v. Shell Oil Co., et al., No. 00-Z-1856 (U.S.D.C. Colo.);
United States ex rel. Crowley v. Shell Oil Company, et al., No. 00-Z-1220
(U.S.D.C. Colo.); Ptasynski et al. v. Shell Western E&P Inc., et al., No.
3:97-CV-1208-R (U.S.D.C. Tex. N. Dist. Dallas Div.); Feerer et al. v. Amoco
Production Co., et al., No. 99-2231 (U.S. Ct. App. 10th Cir.); Shell Western
E&P Inc. v. Bailey, et al., No 98-28630 (215th Dist. Ct. Harris County,
Tex.); Shores, et al. v. Mobil Oil Corporation, et al., No. GC-99-01184
(Texas Probate Court, Denton County); First State Bank of Denton v. Mobil Oil
Corporation, et al., No. PR-8552-01 (Texas Probate Court, Denton County); and
Celeste C. Grynberg v. Shell Oil Company, et al., No. 98-CV-43 (Colo. Dist.
Ct. Montezuma County).
Page 14 of 38
Although no assurances can be given, we believe that we have meritorious
defenses to these actions, that 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.
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 (CERCLA) 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 associated with our SFPP assets:
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, natural gas liquids, natural gas and carbon dioxide.
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.
In the first quarter of 2001, we closed on the purchase of twelve liquid
terminal sites and two pipelines assets from GATX Corporation (see note 2).
Groundwater and soil remediation efforts are currently being performed 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. We have recorded
environmental reserves in the amount of $62.1 million to address the
environmental issues, including CERCLA liabilities, related to these assets.
Although no assurance can be given, we believe that the ultimate resolution
of all these 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 $78.2 million at June 30, 2001.
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.
For more detailed information regarding these proceedings and other
litigation, please refer to Note 16 to our consolidated financial statements
included in our Form 10-K, as amended, for the year ended December 31, 2000.
4. Distributions
On May 15, 2001, we paid a cash distribution for the quarterly period ended
March 31, 2001, of $1.05 per unit.
Page 15 of 38
The distribution was declared on April 18, 2001, payable to unitholders of
record as of April 30, 2001.
On July 18, 2001, we declared a cash distribution for the quarterly period
ended June 30, 2001, of $1.05 per unit. The distribution will be paid on or
before August 14, 2001, to unitholders of record as of July 31, 2001. Common
unitholders and class B unitholders will receive cash. KMR, the sole
i-unitholder, will receive a distribution in the form of additional i-units
based on the $1.05 distribution per unit. The number of i-units distributed will
be calculated by dividing $1.05 by the average of KMR's limited liability
shares' closing market prices from July 13-26, 2001.
5. Debt
Our debt facilities as of June 30, 2001, consist primarily of:
o a $600 million unsecured 364-day credit facility due October 25, 2001;
o a $300 million unsecured five-year credit facility due September
29, 2004;
o $200 million of 8.00% Senior Notes due March 15, 2005;
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 $300 million of 7.40% Senior Notes due March 15, 2031;
o $200 million of Floating Rate Senior Notes due March 22, 2002;
o $119 million of Series F First Mortgage Notes (our subsidiary, SFPP,
is the obligor on the notes);
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 $40 million of 7.84% Senior Notes (our subsidiary, Central Florida
Pipe Line LLC, is the obligor on the notes);
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 a $60.2 million unsecured two-year credit facility due June 29,
2003(Trailblazer Pipeline Company is the obligor on the facility); and
o a $600 million short-term commercial paper program.
Our short-term debt at June 30, 2001, consisted of:
o $5.0 million under the Central Florida Pipeline LLC Notes;
o $2.3 million under the CALNEV Pipe Line LLC Notes; and
o $39.5 million under the SFPP 10.7% First Mortgage Notes.
We intend and have the ability to refinance our short-term debt on a
long-term basis under our existing credit facilities. During the first six
months of 2001, our acquisitions of assets totaled $1,028.4 million. We utilized
our short-term credit facilities and issued long-term debt securities to fund
these acquisitions and then reduced our short-term borrowings with the proceeds
from our May 2001 issuance of i-units. We intend to refinance additional
short-term debt during 2001 through a combination of long-term debt, equity and
the issuance of additional commercial paper to replace maturing commercial paper
borrowings. Based on prior successful short-term debt refinancings and current
market conditions, we do not anticipate any liquidity problems.
For additional information regarding our debt facilities, see Note 9 to our
consolidated financial statements included in our Form 10-K, as amended, for the
year ended December 31, 2000.
Credit Facilities
No borrowings were outstanding under our two credit facilities at June 30, 2001.
During the second quarter of 2001, we terminated our $500 million credit
facility, which was scheduled to expire on December 31, 2001. No borrowings were
outstanding under this credit facility during the second quarter.
Our two credit facilities are with a syndicate of financial institutions.
First Union National Bank is the administrative agent under the agreements.
Interest on our credit facilities accrues at our option at a floating rate equal
to either:
Page 16 of 38
o First Union National Bank'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.
The five-year credit facility also permits us to obtain bids for fixed rate
loans from members of the lending syndicate.
Senior Notes
At June 30, 2001, the unamortized liability balance on the various series of
our senior notes were as follows:
(Dollars in millions)
Series Unamortized Liability Balance
6.30% senior notes due February 1, 2009 $249.4
8.0% senior notes due March 15, 2005 199.7
Floating rate notes due March 22, 2002 200.0
7.5% senior notes due November 1, 2010 248.5
6.75% senior notes due March 15, 2011 698.0
7.40% senior notes due March 15, 2031 299.3
-----
Total $1,894.9
========
At June 30, 2001, the interest rate on our floating rate notes was 4.25%.
Commercial Paper Program
On March 31, 2001, our commercial paper program provided for the issuance of
up to $1.1 billion of commercial paper. During the second quarter, we decreased
the commercial paper program to provide for the issuance of up to $600 million.
Borrowings under our commercial paper program reduce the borrowings allowed
under our credit facilities. As of June 30, 2001, no borrowings were outstanding
under our commercial paper program.
CALNEV Pipe Line LLC Debt
Effective March 31, 2001, we acquired CALNEV Pipe Line LLC (see note 2). As
part of our purchase price, we assumed an aggregate principal amount of $6.8
million of Senior Notes originally issued to a syndicate of five insurance
companies. The Senior Notes had a fixed annual interest rate of 10.07%. In June
2001, we prepaid the balance outstanding under the Senior Notes, plus $0.9
million for interest and a make-whole premium, from cash on hand.
Trailblazer Pipeline Company Debt
At March 31, 2001, Trailblazer's outstanding debt balance included the
following:
o $15.2 million under its 8.03% Senior Secured Notes; and
o $10 million under its 364-day revolving unsecured credit agreement due
December 27, 2001.
On June 26, 2001, Trailblazer prepaid the balance outstanding under the
Senior Secured Notes, plus $0.8 million for interest and a make-whole premium,
using a new two-year unsecured revolving credit facility with a bank
syndication. The new facility provides for loans of up to $60.2 million and
expires June 29, 2003. The agreement provides for an interest rate of LIBOR plus
a margin as determined by certain financial ratios. On June 29, 2001,
Trailblazer paid the $10 million outstanding balance under its 364-day revolving
credit agreement and terminated the agreement. At June 30, 2001, the outstanding
balance under Trailblazer's two-year revolving credit facility was $28 million,
with an interest rate of 4.585%, which reflects three-month LIBOR plus a margin
of 0.875%. Pursuant to the terms of the revolving credit facility, Trailblazer
partnership distributions are restricted by certain financial covenants.
Page 17 of 38
Kinder Morgan Operating L.P. "B" Debt
The $23.7 million principal amount of tax-exempt bonds due 2024 was issued by
the Jackson-Union Counties Regional Port District. These bonds bear interest at
a weekly floating market rate. During the second quarter of 2001, the
weighted-average interest rate on these bonds was 3.38% per annum, and at June
30, 2001, the interest rate was 2.75%.
Cortez Pipeline Company Debt
Pursuant to a certain Throughput and Deficiency Agreement, the owners of
Cortez Pipeline Company are required to contribute capital to Cortez in the
event of a cash deficiency. The agreement contractually supports the financings
of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline
Company, by obligating the owners of Cortez Pipeline to fund cash deficiencies
at Cortez Pipeline, including cash deficiencies relating to the repayment of
principal and interest. Their respective parent or other companies further
severally guarantee the obligations of the Cortez Pipeline owners under this
agreement.
Due to our indirect ownership of Cortez 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's debt programs in place as of April 1, 2000.
At June 30, 2001, the debt facilities of Cortez Capital Corporation consisted
of:
o a $127 million uncommitted 364-day revolving credit facility;
o a $48 million committed 364-day revolving credit facility;
o $136.4 million of series D notes; and
o a $175 million short-term commercial paper program.
At June 30, 2001, Cortez had $151.6 million of commercial paper outstanding
with an interest rate of 4.07%, the average interest rate on the series D notes
was 6.8579% and there were no borrowings under the credit facilities.
6. Partners' Capital
At December 31, 2000, we had 67,514,809 units outstanding, consisting of
64,858,109 common units and 2,656,700 class B units. In accordance with common
unit option exercises during the first six months of 2001, common units were
issued as follows:
o 1,000 units on January 4, 2001;
o 600 units on January 9, 2001
o 400 units on January 10, 2001;
o 900 units on January 19, 2001
o 500 units on January 24, 2001
o 200 units on March 20, 2001;
o 3,000 units on March 21, 2001
o 300 units on April 9, 2001;
o 800 units on April 16, 2001;
o 6,500 units on April 25, 2001;
o 1,200 units on April 27, 2001;
o 4,000 units on May 1, 2001;
o 3,200 units on May 14, 2001;
o 800 units on May 23, 2001; and
o 400 units on May 31, 2001.
We received net proceeds of approximately $996.9 million from KMR for the
issuance of i-units. In accordance with KMR's public offering of limited
liability shares, i-units were issued as follows:
o 1,487,500 units on May 17, 2001; and
Page 18 of 38
o 13,387,500 units on May 18, 2001.
We used the proceeds from the i-unit issuance to reduce the debt we incurred
in our acquisition of GATX Corporation's domestic pipeline and liquids terminal
businesses during the first quarter of 2001. The i-units are a separate class of
limited partner interest in the Partnership. All of the i-units will be owned by
KMR and will not be publicly traded. KMR's limited liability company agreement
provides that the number of all of its outstanding shares shall at all times
equal the number of i-units that it owns. Through the combined effect of the
provisions in our partnership agreement and the provisions of KMR's limited
liability company agreement, the number of outstanding KMR shares and the number
of i-units will at all times be equal.
KMR, as the owner of the i-units, generally will vote together with the
holders of the common units and class B units as a single class. However, the
i-units will vote separately as a class on the following matters:
o amendments to our partnership agreement that would have a material adverse
effect on the holders of the i-units in relation to the other classes of
units. This kind of an amendment requires the approval of two-thirds of
the outstanding i-units, excluding the number of i-units equal to the
number of KMR shares owned by Kinder Morgan, Inc. and its affiliates; and
o the approval of the withdrawal of our general partner or the transfer to a
non-affiliate of all of its interest as our general partner. These matters
require the approval of a majority of the outstanding i-units excluding
the number of i-units equal to the number of KMR shares owned by Kinder
Morgan, Inc. and its affiliates.
In all cases, KMR will vote its i-units in proportion to the affirmative and
negative votes, abstentions and non-votes of owners of KMR shares.
Furthermore, under the terms of our partnership agreement, we agree 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 KMR
will be based upon the amount of cash we distribute to the owners of our common
units. Typically, if cash is paid to the holders of our common units, we will
issue additional i-units to KMR. The fraction of an i-unit paid per i-unit owned
by KMR will have the same value as the cash payment on the common unit. If
additional units are distributed to the holders of our common units, we will
issue an equivalent amount of i-units to KMR based on the number of i-units it
owns.
As a result of the preceding, at June 30, 2001, we had 82,413,609 units
outstanding, consisting of:
o 64,881,909 common units;
o 2,656,700 class B units; and
o 14,875,000 i-units.
Together, 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 common unit total consisted of 53,569,909
common units held by third parties, 10,450,000 common units held by Kinder
Morgan, Inc. and 862,000 common units held by our general partner. The class B
units were held entirely by Kinder Morgan, Inc. and the i-units were held
entirely by KMR. Our 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 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 allocated to our general partner are determined by
the amount that quarterly distributions to unitholders exceed certain specified
target levels. Our distribution of $1.05 per unit paid on May 15, 2001 for the
first quarter of 2001 required an incentive distribution to our general partner
of $41.0 million. Our distribution of $0.775 per unit paid on May 15, 2000 for
the first quarter of 2000 required an incentive distribution to our general
partner of $21.9 million. The increased incentive distribution to our general
partner paid for the first quarter of 2001 over the distribution paid for the
first quarter of 2000 reflects the increase in the amount distributed per unit
as well as the issuance of additional units.
Page 19 of 38
Our declared distribution for the second quarter of 2001 of $1.05 per unit
will result in an incentive distribution to our general partner of $50.1
million. This compares to our distribution of $0.85 per unit and incentive
distribution to our general partner of $26.6 million for the second quarter of
2000. The increased incentive distribution to our general partner paid for the
second quarter of 2001 over the distribution paid for the second quarter of 2000
reflects the increase in the amount distributed per unit as well as the issuance
of additional units.
7. Comprehensive Income
Statement of Financial Accounting Standards No. 130, "Accounting for
Comprehensive Income", requires that enterprises report a total for
comprehensive income. During the second quarter and the first six months of
2001, the only difference between net income and comprehensive income for us was
the unrealized gain or loss on derivatives utilized for hedging purposes. There
was no difference between net income and comprehensive income during the second
quarter or the first six months of 2000. For more information on our hedging
activities, see note 8. Our total comprehensive income is as follows (in
thousands):
Three Months Six Months
Ended Ended
June 30, 2001 June 30, 2001
-------------- --------------
Net income $ 104,226 $ 205,893
Unrealized gain/(loss) on derivatives
utilized for hedging purposes (18,806) (30,963)
----------- -----------
Comprehensive income $ 85,420 $ 174,930
=========== ===========
8. Risk Management
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 and associated transportation, natural gas
liquids, crude oil and carbon dioxide. Our Form 10-K, as amended, for the year
ended December 31, 2000 contains additional information about the risks we face
and the hedging program we employ to mitigate those risks.
Approximately $0.2 million net was recognized in earnings as a loss during
the second quarter of 2001 as a result of ineffectiveness of these hedges, which
amount is reported within the caption "Operations and maintenance" in the
accompanying Consolidated Statements of Income. 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 $3.0 million of the accumulated other comprehensive income balance
of $5.8 million representing unrecognized net losses on derivative activities at
June 30, 2001 is expected to be reclassified into earnings during the next
twelve months. During the quarter ended June 30, 2001, 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.
Page 20 of 38
9. Reportable Segments
We have five reportable business segments:
o Product Pipelines;
o Natural Gas Pipelines;
o CO2 Pipelines;
o Bulk Terminals; and
o Liquids Terminals.
We evaluate performance based on each segments' 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 Product 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 and transmission 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. Our Bulk Terminals segment derives its revenues
primarily from the transloading and storing of dry and liquid bulk products,
including coal, petroleum coke, cement, alumina and salt.
Our Liquids Terminals segment derives its revenues primarily from the storage of
refined petroleum products and chemicals.
Financial information by segment follows (in thousands):
Three Months Ended June 30, Six Months Ended June 30,
2001 2000 2001 2000
-------------- ------------- -------------- --------------
Revenues
Product Pipelines $ 137,181 $ 94,628 $ 327,874 $ 180,750
Natural Gas Pipelines 479,224 40,630 1,205,509 80,686
CO2 Pipelines 32,143 24,619 61,245 24,619
Bulk Terminals 53,143 33,881 101,731 65,061
Liquids Terminals 34,064 - 68,041 -
-------------- ------------- -------------- --------------
Total consolidated revenues $ 735,755 $ 193,758 $ 1,764,400 $ 351,116
============== ============= ============== ==============
Page 21 of 38
Three Months Ended June 30, Six Months Ended June 30,
2001 2000 2001 2000
-------------- ------------- -------------- --------------
Operating income
Product Pipelines $ 80,376 $ 46,790 $ 147,411 $ 89,468
Natural Gas Pipelines 26,807 22,810 80,193 48,187
CO2 Pipelines 16,457 15,551 30,909 15,516
Bulk Terminals 15,437 10,205 28,629 19,569
Liquids Terminals 17,535 - 36,406 -
-------------- ------------- -------------- --------------
Total segment operating income 156,612 95,356 323,548 172,740
Corporate administrative expenses (18,016) (15,380) (46,601) (29,703)
-------------- ------------- -------------- --------------
Total consolidated operating income$ 138,596 $ 79,976 $ 276,947 $ 143,037
============== ============= ============== ==============
Earnings from equity investments, net of amortization of excess costs
Product Pipelines $ 6,266 $ 7,168 $ 11,181 $ 12,976
Natural Gas Pipelines 5,174 3,716 10,450 7,430
CO2 Pipelines 7,454 4,304 16,213 7,926
Bulk Terminals - - - -
Liquids Terminals - - - -
Consolidated equity earnings, net -------------- ------------- -------------- --------------
of amortization of excess costs $ 18,894 $ 15,188 $ 37,844 $ 28,332
============== ============= ============== ==============
Segment earnings
Product Pipelines $ 84,096 $ 53,566 $ 153,944 $ 106,973
Natural Gas Pipelines 31,974 26,531 90,646 55,670
CO2 Pipelines 23,753 20,601 47,215 24,188
Bulk Terminals 13,452 10,380 25,700 19,925
Liquids Terminals 16,875 - 35,706 -
-------------- ------------- -------------- --------------
Total segment earnings 170,150 111,078 353,211 206,756
Interest and corporate
administrative expenses (a) (65,924) (39,268) (147,318) (75,387)
-------------- ------------- -------------- --------------
Total consolidated net income $ 104,226 $ 71,810 $ 205,893 $ 131,369
============== ============= ============== ==============
(a) Includes interest expense, general and administrative expenses, minority
interest and other insignificant items.
June 30, Dec. 31,
Business Segment Assets 2001 2000
-------------- -------------
Product Pipelines $ 3,069,103 $ 2,220,984
Natural Gas Pipelines 1,761,573 1,552,506
CO2 Pipelines 440,705 417,278
Bulk Terminals 446,297 357,689
Liquids Terminals 398,416 -
-------------- -------------
Total segment assets 6,116,094 4,548,457
Corporate assets (b) 145,585 76,753
-------------- -------------
Total consolidated assets $ 6,261,679 $ 4,625,210
============== =============
(b) Includes cash, cash equivalents and certain unallocable related party
receivables and deferred charges.
10. New Accounting Pronouncements Not Yet Adopted
Business Combinations
On June 29, 2001, the Financial Accounting Standards Board unanimously
approved the proposed Statements of Financial Accounting Standards No. 141,
"Business Combinations", which was issued in July 2001. SFAS No. 141 supercedes
Accounting Principles Board Opinion No. 16, and requires that all transactions
fitting the description of a business combination be accounted for using the
purchase method and prohibits the use of the pooling of interests for all
business combinations initiated after June 30, 2001. The statement also modifies
the accounting for the excess of fair value of net assets acquired as well as
intangible assets acquired in a business combination. The provisions of
Page 22 of 38
this statement apply to all business combinations initiated after June 30, 2001,
and all business combinations accounted for by the purchase method that are
completed after July 1, 2001. We are currently evaluating the effects of this
pronouncement.
Goodwill and Other Intangible Assets
On June 29, 2001, the FASB unanimously approved the proposed SFAS No. 142,
"Goodwill and Other Intangible Assets", which was issued in July 2001. SFAS No.
142 supercedes Accounting Principles Board Opinion No. 17 and requires that
goodwill no longer be amortized but should be tested, at least on an annual
basis, for impairment. A benchmark assessment of potential impairment must also
be completed within six months of adopting SFAS No. 142. Other intangible assets
are to be amortized over their useful life and reviewed for impairment in
accordance with the provisions of SFAS No. 121, "Accounting for the Impairment
of Long-Lived Assets and Long-Lived Assets to be Disposed of". Intangible assets
with an indefinite useful life can no longer be amortized until its useful life
becomes determinable. SFAS No. 142 is effective for fiscal years beginning after
December 15, 2001, however, it does apply to any goodwill acquired in a business
combination completed after June 30, 2001. We are currently evaluating the
effects of this pronouncement.
Accounting for Asset Retirement Obligations
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations". This statement requires companies to record a liability relating
to the retirement and removal of assets used in their business. The liability is
discounted to its present 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 are currently evaluating the effects of this
pronouncement.
11. Subsequent Events
On July 12, 2001, we announced that we had acquired four bulk terminals from
Koninklijke Vopak N.V. (Royal Vopak) of The Netherlands for $43.8 million. Two
of the terminals are located in Tampa, Florida. The other two are located in
Fernandina Beach, Florida and Chesapeake, Virginia.
On July 18, 2001, we announced that we had signed a definitive agreement with
an affiliate of Occidental Petroleum Corporation to purchase a partnership that
owns a natural gas pipeline system in the State of Texas for approximately $360
million. At the current time, these assets are leased and operated by Kinder
Morgan Texas Pipeline, L.P., a business unit included in our Natural Gas
Pipelines business segment. The acquisition includes 2,600 miles of pipeline
that primarily transports natural gas from south Texas and the Texas Gulf Coast
to the greater Houston/Beaumont area. The transaction is subject to customary
regulatory approvals and is expected to close in the third quarter of 2001. In
addition, we signed a five-year agreement to supply approximately 90 billion
cubic feet of natural gas to chemical facilities owned by Occidental affiliates
in the Houston area.
On July 18, 2001, our general partner approved a two-for-one unit split of
our outstanding common units. The common unit split will entitle common
unitholders to one additional unit for each unit held. The issuance and mailing
of split units will occur on August 31, 2001 to unitholders of record on August
17, 2001. Our partnership agreement provides that when a split of our common
units occurs, we will effect a unit split on our class B units and on our
i-units to adjust proportionately the number of our class B units and our
i-units.
The following summarized unaudited pro forma net income per unit information
for the three and six months ended June 30, 2001 and 2000, assumes a two-for-one
unit split of our outstanding common units had occurred as of January 1, 2000.
We have prepared this unaudited pro forma financial information for comparative
purposes only. Amounts presented below are in thousands, except for the per unit
amounts:
Page 23 of 38
Pro Forma
Three Months Ended Six Months Ended
June 30, 2001 June 30, 2000 June 30, 2001 June 30,2000
------------- ------------- ------------- ------------
(Unaudited)
Net income $104,226 $71,810 $205,893 $131,369
General Partner's interest
in net income 50,606 27,003 92,228 49,260
Limited Partners' interest
in net income 53,620 44,807 113,665 82,109
Basic Limited Partners' Net
Income per unit $ 0.36 $ 0.35 $ 0.80 $ 0.66
Diluted Limited Partners'
Net Income per unit $ 0.36 $ 0.35 $ 0.80 $ 0.66
Weighted average number of units used in computation
of net income per unit
Basic 149,482 128,128 142,300 123,574
Diluted 149,686 128,176 142,492 123,636
On July 18, 2001, we announced a change in the organization of our business
segments, effective in the third quarter of 2001. We will combine our Bulk
Terminals and Liquids Terminals business segments into a new segment under one
management team. Beginning in the third quarter of 2001, we will report the
combined Bulk Terminals and Liquids Terminals segments as our Terminals segment.
Page 24 of 38
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
Results of Operations
Second Quarter 2001 Compared With Second Quarter 2000
Our second quarter results reflected the continued growth in earnings that
have occurred since the change in control of our general partner in February
1997. Second quarter 2001 net income was a record $104.2 million ($0.72 per
diluted unit), a 45% increase versus the second quarter of 2000. In the second
quarter of 2000, we earned $71.8 million ($0.70 per diluted unit). Our second
quarter revenues totaled $735.8 million in 2001, compared with $193.8 million in
the same year-earlier period.
Our second quarter 2001 results include a full three months of operations
from the pipeline and terminal businesses we acquired from GATX Corporation
during the first quarter. Our second quarter 2001 results also include the
operating results of Delta Terminal Services, Inc., acquired on December 1,
2000, the Natural Gas Pipeline assets we acquired from Kinder Morgan, Inc. on
December 31, 2000, and Pinney Dock & Transport Company, which we acquired on
March 1, 2001. Our strategy of acquiring and growing a strong mix of primarily
fee-based midstream energy assets has continued to deliver strong financial
results. All five of our operating business segments reported quarter-to-quarter
increases in both operating revenues and net income. In addition, for the second
straight quarter, we declared a distribution of $1.05 per unit (an annualized
rate of $4.20), a 24% increase from the second quarter 2000 distribution of
$0.85 per unit.
Total consolidated operating income was $138.6 million in the second quarter
of 2001 versus $80.0 million in the same period last year. Our operating
expenses, consisting of cost of sales, fuel, power and operating and maintenance
expenses, were $527.7 million in the second quarter of 2001 compared with $72.0
million in the same period a year ago. The increase was primarily due to the
acquisitions described above. Second quarter earnings from equity investments,
net of amortization of excess costs, were $18.9 million in 2001 and $15.2
million in 2000. The 24% increase ($3.7 million) in net equity earnings was
mainly due to earnings from Kinder Morgan CO2 Company, L.P.'s 15% interest in
MKM Partners, L.P., an oil and gas joint venture with Marathon Oil Company that
began January 1, 2001.
Product Pipelines
Our Product Pipelines' business segment reported significant
quarter-to-quarter increases in operating results. For the second quarter of
2001, the segment reported earnings of $84.1 million on revenues of $137.2
million. This compares with earnings of $53.6 million on revenues of $94.6
million for the second quarter of 2000. The increases reflect the results of the
following strategic business acquisitions that were made since the second
quarter of last year:
o Kinder Morgan Transmix Company, LLC;
o the remaining 50% interest in the Colton Transmix Processing Facility;
o a 34.8% interest in the Cochin Pipeline System;
o Central Florida Pipeline LLC;
o CALNEV Pipe Line LLC; and
o refined petroleum product and chemical terminals, acquired from GATX
Corporation.
Together, these acquired businesses generated earnings of $23.0 million on
revenues of $42.5 million during the second quarter of 2001. Segment revenue
from assets owned in both years was essentially flat as lower revenues from our
pre-existing Transmix operations offset the fees we earned from becoming the
operator of Plantation Pipe Line Company as well as higher revenues from both
our Pacific operations and our North System. The decrease in transmix revenues
was due to a 10-year marketing agreement, entered into with Duke Energy in the
first quarter of 2001, which transformed our transmix operations into a purely
fee-based enterprise. Our Pacific operations reported an increase in revenues of
$6.0 million (9%) in the second quarter of 2001 compared with the second quarter
of 2000, primarily due to 4% increases in both mainline delivery volumes and
average tariff rates. Our North System reported an increase in revenues of $0.3
million (5%) in the second quarter of 2001 compared with the second quarter of
2000. The increase was due to a 21% increase in throughput volumes, primarily
the result of transporting higher volumes in and around the Chicago area for Aux
Sable Liquid Products. The segment's combined operating expenses totaled $34.4
million for both quarters. The operating expenses from our newly acquired
businesses were offset by a decrease in transmix purchasing costs, as a result
of the marketing agreement with Duke Energy. Segment operating income was $80.4
Page 25 of 38
million and equity earnings, net of amortization of excess costs, were $6.3
million for the current quarter. During the second quarter of 2000, the segment
reported operating income of $46.8 million and equity earnings, net of
amortization, of $7.2 million. The $0.9 million decrease in equity earnings was
mainly due to the absence of equity earnings from the Colton Transmix Processing
Facility due to the fact that we acquired the remaining 50% interest in the
facility on December 31, 2000, and since that date, we no longer account for
this investment on an equity basis.
Natural Gas Pipelines
Our Natural Gas Pipelines segment reported earnings of $32.0 million on
revenues of $479.2 million during the second quarter of 2001. For the second
quarter of 2000, the segment earned $26.5 million on revenues of $40.6 million.
The quarter-to-quarter increases were primarily due to the inclusion of assets
acquired from Kinder Morgan, Inc. on December 31, 2000. Effective on that date,
we acquired:
o Kinder Morgan Texas Pipeline, L.P.;
o the Casper and Douglas Natural Gas Gathering and Processing Systems;
o a 50% interest in Coyote Gas Treating, LLC; and
o a 25% interest in Thunder Creek Gas Services, LLC.
Combined, these assets produced earnings of $5.5 million on revenues of
$436.8 million during the second quarter of 2001. The $438.6 million overall
increase in segment revenues includes a $2.0 million increase in revenues earned
by Kinder Morgan Interstate Gas Transmission LLC, primarily due to revenues
attributable to fuel recoveries, partially driven by a reduction in fuel lost.
Segment operating expenses totaled $442.5 million in the second quarter of 2001
and $11.5 million in the second quarter of 2000. The overall increase of $431.0
million in combined operating expenses includes $428.6 million of cost of sales
and other expenses from the assets acquired in 2000 and a $2.3 million increase
in expenses incurred by Kinder Morgan Interstate Gas Transmission LLC, primarily
the result of higher fuel costs on purchased natural gas. Segment operating
income was $26.8 million in the second quarter of 2001 versus $22.8 million in
the second quarter of 2000. Earnings from equity investments, net of
amortization, were $5.2 million for the second quarter of 2001 and $3.7 million
for the same prior year period. The $1.5 million increase in equity earnings
resulted from the inclusion of $0.8 million of net equity earnings from the
segment's investments in Coyote and Thunder Creek and a $0.7 million increase in
earnings from its 49% interest in the Red Cedar Gathering Company.
CO2 Pipelines
Our CO2 Pipelines segment reported earnings of $23.8 million on revenues of
$32.1 million in the second quarter of 2001. The segment earned $20.6 million on
revenues of $24.6 million in the same period last year. The increase in second
quarter earnings and revenues in 2001 over 2000 was primarily due to the
inclusion of operating results from the working interests in oil and natural gas
producing properties that we acquired from Devon Energy on June 1, 2000. The
purchased properties, including an approximate 71% interest in the SACROC oil
field, were also the main contributors to higher quarterly segment operating
expenses. Total combined operating expenses for the segment totaled $9.3 million
for the three months ended June 30, 2001 and $5.8 million for the same three
months in 2000. Segment operating income was $16.5 million in the second quarter
of 2001 versus $15.6 million in the second quarter of 2000. Earnings from equity
investments, net of amortization of excess costs, were $7.5 million for the
second quarter of 2001 and $4.3 million for the same year-ago period. The $3.2
million increase in net equity earnings resulted from the inclusion of $2.4
million of net equity earnings from the segment's 15% equity investment in MKM
Partners, L.P. and a $0.8 million increase in equity earnings from its 50%
interest in Cortez Pipeline Company.
Bulk Terminals
Bulk Terminals reported earnings of $13.5 million on revenues of $53.1
million in the second quarter of 2001. These amounts compare to earnings of
$10.4 million on revenues of $33.9 million in the second quarter of 2000. The
increases reflect the results of the following business acquisitions that were
made since the second quarter of last year:
o Delta Terminal Services, Inc.; and
o Pinney Dock & Transport Company.
Together, these acquired terminal businesses generated earnings of $6.4
million on revenues of $15.4 million during
Page 26 of 38
the second quarter of 2001. The segment reported a $3.8 million increase in
revenues from operations owned in the second quarter of both years. This
increase resulted primarily from higher revenues earned from engineering
services for project work overseas, and from an increase in bulk tonnage
volumes. In addition, revenues at our Cora and Grand Rivers coal terminals
increased $0.8 million (13%) in the second quarter of 2001 compared with the
second quarter of 2000, mainly due to a 17% increase in transloaded coal
volumes, partially offset by a 5% decrease in average coal transfer rates. Our
Shipyard River Terminal generated an increase of $0.3 million to segment
operating revenues in the second quarter of 2001. The increase was due to a 68%
increase in Shipyard's tonnage volume, resulting from improvements made during
2000, including the acquisition of a second dock and the construction of
additional covered storage and new connecting conveyor systems. Segment
operating expenses totaled $32.3 million in the second quarter of 2001 compared
with $20.3 million in the first quarter of 2000. The $12.0 million overall
increase in combined segment operating expenses includes $7.3 million in
expenses from our recently acquired Delta and Pinney Dock operations, and a $2.6
million increase in engineering operating expenses, related to the increase in
services performed. Operating income for the segment was $15.4 million in the
second quarter of 2001 versus $10.2 million for the same year-earlier period.
Liquids Terminals
Our Liquids Terminals segment reported earnings of $16.9 million on revenues
of $34.1 million for the quarter ended June 30, 2001. This segment consists of
five liquid and chemical terminals that we acquired from GATX Corporation on
January 1, 2001. Two of the terminals are located in the Houston, Texas area,
and one each in New York, Chicago and Philadelphia. For the second quarter of
2001, the segment reported operating expenses of $9.2 million and operating
income of $17.5 million.
Segment Operating Statistics
Operating statistics for the second quarter of 2001 and 2000 are as follows:
Three Months Ended
June 30, 2001 June 30, 2000
------------- -------------
Product Pipelines
Delivery Volumes (MBbl)(1) 197,973 192,926
Natural Gas Pipelines
Transport Volumes (Bcf)(2) 108.3 112.8
CO2 Pipelines
Delivery Volumes (Bcf) (3) 93.2 90.7
Bulk Terminals
Transload Tonnage (Mtons)(4) 12,399 10,116
Liquids Terminals
Throughput Volumes (MBbl)(5) 125,580 105,502
(1) Includes Pacific, Plantation, North System, CALNEV, Central Florida,
Cypress and Heartland. 2000 information for CALNEV and Central Florida
included for comparative purposes only.
(2) Includes KMIGT and Trailblazer.
(3) Includes Cortez, Central Basin and Canyon Reef Carriers pipeline
volumes. 2000 information for comparative purposes only.
(4) Includes Cora, Grand Rivers and Kinder Morgan Bulk Terminals aggregate
terminals.
(5) Includes five terminals in Houston, New Jersey, Chicago and
Philadelphia. 2000 information for comparative purposes only.
Other
Items not attributable to any segment include general and administrative
expenses, interest income and expense and minority interest. General and
administrative expenses totaled $18.0 million in the second quarter of 2001
compared with $15.4 million in the same period last year. The increase was
principally associated with the businesses we acquired since June 30, 2000 and
the administrative expenses incurred from assuming the operating duties of
Plantation Pipe Line Company. Our total interest expense, net of interest
income, was $45.3 million in the second quarter of 2001 compared with $21.8
million in the same year-earlier period. Although we reduced our outstanding
debt significantly during the second quarter of 2001, the increase in
quarter-to-quarter net interest expense was primarily due to the additional debt
we issued related to the financing of the acquisitions that we have made since
the end of the second quarter of 2000 and to the $134.7 million in third-party
debt we assumed as part of
Page 27 of 38
the net assets acquired from GATX Corporation. Minority interest increased to
$2.6 million for the second quarter of 2001 versus $2.1 million in the second
quarter of 2000. The $0.5 million increase was mainly due to an increase in
earnings attributable to the minority interest in Kinder Morgan Texas Pipeline,
L.P. and its consolidated subsidiaries.
We reported an increase in income tax expense of $1.4 million in the second
quarter of 2001 compared to last year's second quarter. The increase was due to
higher earnings attributable to Kinder Morgan Bulk Terminals, Inc.
Six Months Ended June 30, 2001 Compared With Six Months Ended June 30, 2000
Net income for the six months ended June 30, 2001 were $205.9 million ($1.60
per diluted unit) compared with net income of $131.4 million ($1.33 per diluted
unit) in the first six months of 2000. For the second consecutive year, we
realized a 56% increase in net income for the comparable January through June
six-month periods. We reported total revenues of $1,764.4 million for the first
half of 2001 versus $351.1 million for the first half of last year. The
increases in revenues and earnings occurred across all five of our business
segments, reflecting key acquisitions made since the second quarter of 2000 and
continued strong demand for our transportation and terminal-related services.
Our operating expenses for the six-month period ended June 30, 2001, were
$1,345.7 million, and for the six-month period ended June 30, 2000, were $127.1
million. Operating income for the six months ended June 30, 2001, was $276.9
million, an increase of 94% compared with the $143.0 million in operating income
reported in the year-earlier period. Equity earnings from investments, less
amortization of excess costs, were $37.8 million in the first six months of 2001
versus $28.3 million in the first six months of 2000.
The increases in overall revenues, expenses and net income in the first six
months of 2001 compared to the first six months of 2000 primarily resulted from
the inclusion of our Liquids Terminals segment, Central Florida Pipeline LLC,
CALNEV Pipe Line LLC and additional refined product terminals, all of which were
acquired from GATX Corporation in the first quarter of 2001. The 2001 results
also include the operating results of Kinder Morgan Transmix Company, LLC, which
we acquired in October 2000, Delta Terminal Services, Inc., which we acquired on
December 1, 2000, the Natural Gas Pipeline assets we acquired from Kinder
Morgan, Inc. on December 31, 2000, Pinney Dock & Transport Company, which we
acquired on March 1, 2001 and Kinder Morgan CO2 Company, L.P. We acquired the
remaining 80% ownership interest in Kinder Morgan CO2 Company, L.P. (formerly
Shell CO2 Company, Ltd.) on April 1, 2000. Prior to that date, we owned a 20%
equity interest in Kinder Morgan CO2 Company, L.P. and reported its results
under the equity method of accounting. The results of Kinder Morgan CO2 Company,
L.P. are included in our CO2 Pipelines segment.
Product Pipelines
Product Pipelines reported earnings of $153.9 million on revenues of $327.9
million for the first six months of 2001. These amounts compare with earnings of
$107.0 million on revenues of $180.8 million for the same period of 2000.
Segment operating expenses totaled $138.2 million for the six months ended June
30, 2001, and $64.4 million for the six-month period ended June 30, 2000. The
increases in revenues and operating expenses resulted primarily from the
inclusion of the pipelines and terminals that we acquired from GATX during the
first quarter of 2001, the inclusion of Kinder Morgan Transmix Company, LLC,
which we acquired from Buckeye Refining Company, LLC in October 2000 and the
operations of Plantation Pipe Line Company, which we assumed on December 21,
2000. Segment revenues attributable to these businesses totaled $136.5 million
for the first half of 2001. Revenues from our Pacific operations totaled $140.1
million, an 8% increase from the $129.3 million reported in the same
year-earlier period. The increase resulted from an over 4% increase in mainline
delivery volumes accompanied by a 3% increase in average tariff rates. On our
North System, half-year revenues totaled $17.4 million in 2001, a 7% increase
from the $16.3 million reported in 2000. Higher deliveries to refineries and
customers resulted in an 11% increase in throughput volumes, partially offset by
a slight decrease (1%) in the six-month average tariff rates. Segment operating
income was $147.4 million and equity earnings, net of amortization of excess
costs, were $11.2 million for the six months ended June 30, 2001. Last year, the
segment reported operating income of $89.5 million and equity earnings, net of
amortization, of $13.0 million. The decrease in equity earnings was mainly due
to the absence of equity earnings from the Colton Transmix Processing Facility
during 2001. On December 31, 2000, we acquired the remaining 50% interest in the
facility and since that date, we have included Colton's operational results in
our consolidated financial statements. For the six-month periods in each of the
years 2001 and 2000, equity earnings from our 51% interest in Plantation Pipe
Line Company have remained constant at $11.0 million.
Page 28 of 38
Natural Gas Pipelines
Our Natural Gas Pipelines segment reported earnings of $90.6 million on
revenues of $1,205.5 million in the first six months of 2001. For the same
period last year, the segment earned $55.7 million on revenues of $80.7 million.
The $1,124.8 million overall increase in period-to-period segment revenues
included $1,104.0 million in revenues earned by Kinder Morgan Texas Pipeline,
L.P. and by the segment's Casper and Douglas gas gathering and processing
assets, both acquired on December 31, 2000. The overall increase in revenues
also included a $22.4 million increase in revenues earned by Kinder Morgan
Interstate Gas Transmission LLC, mainly due to higher fuel recovery revenues,
partially driven by a reduction in fuel lost. Segment operating expenses totaled
$1,104.6 million in the first six months of 2001 and $18.1 million in the first
six months of 2000. The overall increase of $1,086.5 million resulted primarily
from the inclusion of $1,070.6 million of expenses from the assets acquired in
December 2000, including gas purchase costs of $995.2 million incurred by Kinder
Morgan Texas Pipeline, L.P. The overall increase in expenses also included a
$13.5 million increase in the gas purchase costs of Kinder Morgan Interstate Gas
Transmission LLC and Trailblazer, primarily due to higher fuel recovery costs.
Segment operating income was $80.2 million in the first six-month period of 2001
versus $48.2 million in the same period last year. Earnings from equity
investments, net of amortization, were $10.4 million for the six months ended
June 30, 2001 and $7.4 million for the same prior year period. The $3.0 million
overall increase in equity earnings resulted from the inclusion of $1.6 million
of net equity earnings from the segment's investments in Coyote and Thunder
Creek and a $1.4 million increase in earnings from its 49% interest in the Red
Cedar Gathering Company.
CO2 Pipelines
Our CO2 Pipelines segment reported earnings of $47.2 million on revenues of
$61.2 million in the first six months of 2001. The segment reported earnings of
$24.2 million on revenues of $24.6 million in the same six-month period of 2000.
The operating results for the first half of 2000 include three months of equity
earnings from our original 20% interest in Kinder Morgan CO2 Company, L.P. Under
the terms of the prior Kinder Morgan CO2 Company, L.P. partnership agreement,
such earnings were limited to $3.6 million per quarter and results were reported
under the equity method of accounting. After our acquisition of the remaining
80% interest in Kinder Morgan CO2 Company, L.P. on April 1, 2000, its financial
results were included in our consolidated results and we reported its 50%
interest in Cortez Pipeline Company under the equity method of accounting. For
the first six months of 2001, CO2 Pipelines reported operating expenses of $17.8
million, operating income of $30.9 million and equity earnings, net of
amortization of excess costs, of $16.2 million. For the same period last year,
the segment reported operating expenses of $5.8 million, operating income of
$15.5 million and equity earnings, net of amortization, of $7.9 million. The
equity earnings realized in the first six months of 2001 included $10.9 million
from the segment's equity interest in Cortez, and $5.3 million from its 15%
interest in MKM Partners, L.P. For the first six months of 2000, the equity
earnings included the $3.6 million for our first quarter interest in Kinder
Morgan CO2 Company, L.P. and $4.3 million for our second quarter interest in
Cortez.
Bulk Terminals
Bulk Terminals reported earnings of $25.7 million on revenues of $101.7
million for the first six months of 2001. For the same six-month period of 2000,
the segment earned $19.9 million on revenues of $65.1 million. The $36.6 million
increase in period-to-period revenues included $26.5 million in revenues earned
by Delta and Pinney Dock and a $5.7 million increase in engineering service
revenues. Segment operating expenses totaled $62.9 million in the first half of
2001 compared with $38.8 million for the first half of 2000. The $24.1 million
overall increase in combined segment operating expenses includes $13.4 million
in expenses from Delta and Pinney Dock operations, and a $4.5 million increase
in engineering expenses, driven by the increase in services performed. Operating
income for the segment was $28.6 million in the first six months of 2001 and
$19.6 million in the first six months of 2000.
Liquids Terminals
Our Liquids Terminals segment reported earnings of $35.7 million on revenues
of $68.0 million for the six months ended June 30, 2001. For the same period,
the segment reported operating expenses of $22.1 million and operating income of
$36.4 million.
Segment Operating Statistics
Operating statistics for the first six months of 2001 and 2000 are as
follows:
Page 29 of 38
Six Months Ended
June 30, 2001 June 30, 2000
------------- -------------
Product Pipelines
Delivery Volumes (MBbl)(1) 369,943 357,562
Natural Gas Pipelines
Transport Volumes (Bcf)(2) 217.4 220.6
CO2 Pipelines
Delivery Volumes (Bcf)(3) 191.9 185.0
Bulk Terminals
Transload Tonnage (Mtons)(4) 24,079 21,157
Liquids Terminals
Throughput Volumes (MBbl)(5) 233,823 208,265
(1) Includes Pacific, Plantation, North System, CALNEV, Central Florida,
Cypress and Heartland. 2000 information for CALNEV and Central Florida
included for comparative purposes only.
(2) Includes KMIGT and Trailblazer.
(3) Includes Cortez, Central Basin and Canyon Reef Carriers pipeline
volumes. 2000 information for comparative purposes only.
(4) Includes Cora, Grand Rivers and Kinder Morgan Bulk Terminals aggregate
terminals.
(5) Includes five terminals in Houston, New Jersey, Chicago and
Philadelphia. 2000 information for comparative purposes only.
Other
Items not attributable to any segment include general and administrative
expenses, interest income and expense and minority interest. General and
administrative expenses were $46.6 million in the six-month period ended June
30, 2001 and $29.7 million in the six-month period ended June 30, 2000. The
increase was chiefly due to the businesses we acquired and the organizational
changes we have made since June 30, 2000. We continue to manage aggressively our
administrative expenses as we continue to benefit from growth across our
portfolio of businesses. Our total interest expense, net of interest income, was
$95.1 million in the first six months of 2001 compared with $41.9 million in the
same year-earlier period. The increase was due to higher average debt balances
and higher average borrowing rates. Minority interest amounted to $5.6 million
for the six months ended June 30, 2001 and $3.8 million for the same period last
year. The $1.8 million increase was mainly due to the $0.8 million minority
interest in Kinder Morgan Texas Pipeline, L.P. and its consolidated subsidiaries
and a $0.8 million increase in the 33 1/3% minority interest in Trailblazer
Pipeline Company, as a result of higher earnings.
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 our common unitholders, class B
unitholders and general partner. 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. In general, 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 and working capital deficits 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.
At June 30, 2001, our current commitments for capital expenditures were
approximately $20.1 million. This amount has primarily been committed for the
purchase of plant and equipment. We expect to fund these commitments through
additional borrowings or the issuance of additional units. All of our capital
expenditures, with the exception of sustaining capital expenditures, are
discretionary.
Page 30 of 38
Operating Activities
Net cash provided by operating activities was $282.0 million for the six
months ended June 30, 2001, versus $104.6 million in the comparable period of
2000. The $177.4 million increase in our period-to-period cash flows from
operations was predominantly due to a $92.3 million improvement in cash earnings
driven by the business acquisitions and capital investments we have made since
the end of the second quarter of 2000. An increase of $47.7 million was due to
tariff rate refund payments made in the second quarter of 2000. The payment of
the rate refunds was made under settlement agreements between shippers and our
Natural Gas Pipelines. Additionally, we generated $42.8 million from the net
settlement of financial instruments during the first six months of 2001. These
settlements relate to futures and options contracts, fixed-price swaps and basis
swaps that are used as hedging mechanisms against price volatility associated
with the sale, purchase and storage of natural gas, natural gas liquids, crude
oil and carbon dioxide.
Investing Activities
Net cash used in investing activities was $1,139.6 million for the six months
ended June 30, 2001, compared to $616.2 million in the comparable 2000 period.
The $523.4 million period-to-period increase in funds utilized in investing
activities was mainly attributable to a $455.9 million increase in funds used
for strategic acquisitions. Our outlays for the acquisition of new businesses
during the first six months of 2001 totaled $1,028.4 million and included:
o $455.1 million for Kinder Morgan Liquids Terminals LLC;
o $352.1 million for CALNEV Pipe Line LLC;
o $168.2 million for Central Florida Pipeline LLC; and
o $41.5 million for Pinney Dock & Transport Company.
In addition, funds employed for capital expenditures increased $56.6 million
(to $109.2 million) during the 2001 period versus the comparable 2000 period.
The increase was driven primarily by continued investment in our CO2 Pipelines
(Kinder Morgan CO2 Company, L.P.), Natural Gas Pipelines and Bulk Terminals
business segments. In the first quarter of 2000, Kinder Morgan CO2 Company, L.P.
was accounted for under the equity method of accounting. All funds classified as
additions to property, plant and equipment include both expansion and sustaining
capital expenditures.
Financing Activities
Net cash provided by financing activities amounted to $914.7 million for the
six months ended June 30, 2001. The increase of $410.1 million from the
comparable 2000 period was mainly the result of $996.9 million received as
proceeds from our May 2001 offering of i-units to KMR. The overall
period-to-period increase in funds provided by financing activities was offset
by:
o a $297.2 million decrease in funds provided from debt financing
activities;
o a $170.5 million decrease in proceeds received from the issuance of
common units; and
o an $88.0 million increase in distributions to all partners.
Overall debt financing activities, consisting of debt issuance and payments,
provided $156.6 million during the first six months of 2001 versus $453.8
million during the same 2000 period. During the first quarter of 2001, we
completed a public offering of $1.0 billion in principal amount of senior notes,
resulting in a net cash inflow of approximately $990 million net of discounts
and issuing costs. We primarily used the proceeds to purchase the pipeline and
terminal businesses we acquired during the first half of 2001. We used the
proceeds from the issuance of i-units to reduce the outstanding balance on our
credit facilities and commercial paper borrowings. The decrease in proceeds
received from the issuance of common units reflects the $171.2 million we
received from our public offering of 4,500,000 common units in April 2000.
Cash distributions to all partners increased to $214.7 million in the
six-month period ended June 30, 2001, compared to $126.7 million in the
corresponding 2000 period. No distributions of i-units were made during the six
months ended June 30, 2001. The increase in cash distributions was due to:
o an increase in the per unit cash distributions paid;
Page 31 of 38
o an increase in the number of units outstanding; and
o an increase in the general partner incentive distributions, which
resulted from increased cash distributions.
We paid a distribution of $1.05 per unit in the second quarter of 2001
compared with a distribution of $0.775 per unit in the second quarter of 2000.
The 35% increase in paid distributions per unit resulted from favorable
operating results in 2001. On July 18, 2001, we declared a distribution of $1.05
per unit for the second quarter of 2001. 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.
Partnership Distributions
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.
Our general partner is granted discretion by our partnership agreement, which
discretion has been delegated to KMR, subject to the approval of our general
partner, 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 KMR determines our quarterly distributions, KMR considers
current and expected reserve needs along with current and expected cash flows to
identify the appropriate sustainable distribution level.
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.
Typically, our general partner and owners of our common units and class B
units receive distributions in cash, while KMR, 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 market price of
a common unit over the ten consecutive trading days preceding the date on which
the common units begin to trade ex-dividend under the rules of the principal
exchange on which the common units are listed. 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 the related cash but will retain the cash and use the cash in our
business.
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 $0.3025 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 $0.3575 per unit in cash or
equivalent i-units for such quarter;
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 $0.4675 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.
On July 18, 2001, our general partner approved a two-for-one unit split of
our outstanding common units. The common unit split will entitle common
unitholders to one additional unit for each unit held. The issuance and mailing
of split units will occur on August 31, 2001 to unitholders of record on August
17, 2001. Our partnership agreement provides that when a split of our common
units occurs, we will effect a unit split on our class B units and on our
i-units to adjust proportionately the number of our class B units and our
i-units. As a result of the unit split, the above dollar amounts will be reduced
by one-half.
Page 32 of 38
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 second quarter of 2001 was $50.1 million, while the incentive
distribution paid to our general partner was $41.0 million during the second
quarter of 2001 and $21.9 million during the second quarter of 2000.
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 by comparable terminology. In particular, statements,
express or implied, concerning future actions, conditions or events or 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 any difficulties or delays experienced by railroads 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 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 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 or other causes;
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.
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, as amended, for the year ended December 31, 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 our 2000 Form 10-K, as
amended. 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,
2000, in Item 7a of our 2000 Form 10-K, as amended. For more information on our
risk management activities, see Note 8 to our consolidated financial statements
included elsewhere in this report.
Page 33 of 38
PART II. OTHER INFORMATION
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
Item 1. Legal Proceedings.
See Part I, Item 1, Note 3 to Consolidated Financial Statements entitled
"Litigation and Other Contingencies" which is incorporated herein by reference.
Item 2. Changes in Securities and Use of Proceeds.
(a) and (b)
In connection with the issuance of the i-units, our partnership agreement was
amended to provide that we will not:
o 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 the i-units;
o make a distribution on a common unit or class B unit other than in cash,
additional common units or class B units or a security that has in all
material respects the same rights and privileges as the common units or
class B units;
o allow an owner of common units or Class B units to receive any
consideration other than cash, common units or a security that has in all
material respects the same rights and privileges as the common units or
class B units, or allow KMR as the owner of the i-units to receive any
consideration other than i-units or a security that has in all material
respects the same rights and privileges as the i-units, in a:
o merger in which we are not the survivor, if our unitholders immediately
prior to the transaction own more than 50% of the common equity
securities of the survivor immediately after the transaction;
o merger in which we are the survivor if our unitholders immediately
prior to the transaction own more than 50% of our limited partner
interests immediately after the transaction; or
o recapitalization, reorganization or similar transaction;
o be a party to a merger, sell substantially all of our assets to another
person, or enter into similar transactions, if:
o the survivor of the merger or the other person is to be controlled by
Kinder Morgan, Inc. or its affiliates after the transaction; and
o the transaction would be a mandatory purchase event;
o make a tender offer for our common units unless the consideration:
o is exclusively cash; and
o together with any cash payable in respect of any tender offer by us
for the common units concluded within the preceding 360 days and the
aggregate amount of any cash distributions to all owners of common
units made within the preceding 360-day period is less than 12% of
the aggregate average market value of all classes of our units
determined on the trading day immediately preceding the commencement
of the tender offer; or
o issue any of our i-units to any person other than KMR.
In addition, our partnership agreement was amended to provide that we will
adjust proportionately the number of i-units held by KMR through the payment to
KMR of an i-unit distribution or by causing an i-unit subdivision, split or
combination if various events occur, including:
Page 34 of 38
o the payment of a common unit distribution on the common units; and
o a subdivision, split or combination of the common units.
Our partnership agreement was also amended to provide that owners of i-units
generally will vote together with the common units and class B units as a single
class and sometimes will vote as a class separate from the holders of common
units and class B units. The i-units will have the same voting rights as the
common units and class B units voting together as a single class on the
following matters:
o a sale or exchange of all or substantially all of our assets;
o the election of a successor general partner in connection with the
removal of the general partner;
o a dissolution or reconstitution of us;
o a merger of us; and
o some amendments to our partnership agreement, including any amendment that
would cause us to be treated as a corporation for income tax purposes.
The i-units will vote separately as a class on the following:
o Amendments to our partnership agreement that would have a material adverse
effect on the holders of the i-units in relation to the other classes of
units. This kind of an amendment requires the approval of two-thirds of
the outstanding i-units other than the number of i-units corresponding to
the number of shares owned by Kinder Morgan, Inc. and its affiliates.
o The approval of the withdrawal of the general partner or the transfer to a
non-affiliate of all of its interest as a general partner. These matters
require the approval of a majority of the outstanding i-units other than
the number of i-units corresponding to the number of shares owned by
Kinder Morgan, Inc. and its affiliates.
In all cases, i-units will be voted in proportion to the affirmative and
negative votes, abstentions and non-votes of owners of KMR's shares.
(c) During the quarter ended June 30, 2001, we did not issue any equity
securities that were not registered under the Securities Act of 1933, as
amended.
(d) Not applicable.
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
3.1 - Third Amended and Restated Agreement of Limited Partnership of Kinder
Morgan Energy Partners, L.P.
4.1 - Form of certificate representing the i-units of Kinder Morgan Energy
Partners, L.P. (included as an exhibit to the Third Amended and Restated
Agreement of Limited Partnership filed as Exhibit 3.1 hereto).
Page 35 of 38
4.2 - Registration Rights Agreement between Kinder Morgan Energy Partners,
L.P. and Kinder Morgan, Inc.
4.3 - 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.
10.1 Delegation of Control Agreement among Kinder Morgan Management, LLC,
Kinder Morgan G.P., Inc. and Kinder Morgan Energy Partners, L.P. and its
operating partnerships.
---------------------
(b) Reports on Form 8-K.
Amendment No. 1 to the current report dated February 16, 2001 was filed on
April 5, 2001. We filed the following documents as exhibits pursuant to Item
7:
o our financial statements as of December 31, 1999 and 2000 and for each
of the three years in the period ended December 31, 2000;
o Management's Discussion and Analysis of Financial Condition and Results
of Operation for the periods covered by the above financial statements;
o our unaudited Selected Financial Data for each of the five years ended
December 31, 2000;
o the Balance Sheet at December 31, 2000, of Kinder Morgan G.P., Inc., our
general partner and a wholly-owned subsidiary of Kinder Morgan, Inc.;
o the financial statements of the GATX Terminals Companies as of December
31, 2000 and for the year then ended; and
o our unaudited pro forma combined financial statements, derived from our and
the GATX Terminals Companies' historical balance sheets and income
statements, giving effect to our acquisition of the GATX Terminals
Companies as of December 31, 2000 and for the year then ended.
Amendment No. 2 to the current report dated January 20, 2000 was filed on
April 5, 2001. Audited financial statements of the businesses acquired by us and
our unaudited pro form condensed combined statement of income, giving effect to
the acquisition of that portion of our Natural Gas Operations assets and our
additional 33 1/3% interest in Trailblazer Pipeline Company acquired on December
31, 1999, was disclosed pursuant to Item 7.
Report dated April 18, 2001, on Form 8-K was filed on May 2, 2001, pursuant
to Items 5 and 7 of that form. We reported that we issued a press release on
April 18, 2001, announcing that we had increased our unitholder distribution for
the first quarter of 2001 to $1.05 (an annualized rate of $4.20) per unit
payable on May 15, 2001 to unitholders of record as of April 30, 2001. We
reported that the distribution for the first quarter of 2001 was 35% higher than
the distribution paid for the first quarter of 2000, and 11% higher than the
distribution paid for the fourth quarter of 2000. A copy of the press release
was filed as an exhibit pursuant to Item 7.
Amendment No. 3 to the current report dated January 20, 2000 was filed on
April 27, 2001. Audited financial statements of the businesses acquired by us
and our unaudited pro form condensed combined statement of income, giving effect
to the acquisition of that portion of our Natural Gas Operations assets and our
additional 33 1/3% interest in Trailblazer Pipeline Company acquired on December
31, 1999, was disclosed pursuant to Item 7.
Amendment No. 2 to the current report dated February 16, 2001 was filed on
April 27, 2001. We filed the following documents as exhibits pursuant to
Item 7:
o our financial statements as of December 31, 1999 and 2000 and for each
of the three years in the period ended December 31, 2000;
o Management's Discussion and Analysis of Financial Condition and Results
of Operation for the periods covered by the above financial statements;
o our unaudited Selected Financial Data for each of the five years ended
December 31, 2000;
Page 36 of 38
o the Balance Sheet at December 31, 2000, of Kinder Morgan G.P., Inc., our
general partner and a wholly-owned subsidiary of Kinder Morgan, Inc.;
o the financial statements of the GATX Terminals Companies as of December
31, 2000 and for the year then ended; and
o our unaudited pro forma combined financial statements, derived from our
and the GATX Terminals Companies' historical balance sheets and income
statements, giving effect to our acquisition of the GATX Terminals
Companies as of December 31, 2000 and for the year then ended.
Report dated May 2, 2001, on Form 8-K was filed on May 2, 2001, pursuant to
Items 5 and 7 of that form. We reported that we plan to jointly develop the
Sonoran Pipeline, subject to a successful open season and all other approvals.
The Sonoran Pipeline will be a 1,160-mile, high-pressure interstate natural gas
pipeline extending from the San Juan Basin in northern New Mexico to markets in
California. The interstate pipeline will be evaluated and developed in two
phases, which will be subject to the jurisdiction of the Federal Energy
Regulatory Commission. The first phase, expected to be completed in the summer
of 2003, will run from the San Juan Basin to the California border. The second
phase will extend from the California border to the San Francisco Bay area. A
copy of the press release was filed as an exhibit pursuant to Item 7.
Report dated June 25, 2001, on Form 8-K was filed on June 26, 2001, pursuant
to Item 9 of that form. We provided notice that on June 26, 2001, 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 discuss at the 11th Annual
Nantucket Conference Sponsored by First Union Securities on June 26, 2001 at
approximately 9:30 a.m. Eastern Time various strategic and financial issues
relating to the business plans and objectives of ourselves, 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
analyst meeting by visiting Kinder Morgan, Inc.'s website at: http://www.
kindermorgan.com/investor_relations/presentations/kmi_first_union.pdf.
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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: August 3, 2001
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