UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
F O R M 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2002
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____
Commission file number: 1-11234
KINDER MORGAN ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
DELAWARE 76-0380342
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
500 Dallas Street, Suite 1000, Houston, Texas 77002
(Address of principal executive offices)(zip code)
Registrant's telephone number, including area code: 713-369-9000
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No
The Registrant had 129,928,618 common units outstanding at August 2, 2002.
1
KINDER MORGAN ENERGY PARTNERS, L.P.
TABLE OF CONTENTS
Page
Number
PART I. FINANCIAL INFORMATION
Item 1: Financial Statements (Unaudited)...............................
Consolidated Statements of Income-Three and Six
Months Ended June 30, 2002 and 2001.......................... 3
Consolidated Balance Sheets-June 30, 2002 and
December 31, 2001............................................ 4
Consolidated Statements of Cash Flows-Six Months
Ended June 30, 2002 and 2001................................. 5
Notes to Consolidated Financial Statements................... 6-30
Item 2: Management's Discussion and Analysis of Financial
Condition and Results of Operations............................
Results of Operations........................................ 31
Financial Condition.......................................... 36
Information Regarding Forward-Looking Statements............. 39
Item 3: Quantitative and Qualitative Disclosures About
Market Risk.................................................... 40
` PART II. OTHER INFORMATION
Item 1: Legal Proceedings.............................................. 41
Item 2: Changes in Securities and Use of Proceeds...................... 41
Item 3: Defaults Upon Senior Securities................................ 41
Item 4: Submission of Matters to a Vote of Security Holders............ 41
Item 5: Other Information.............................................. 41
Item 6: Exhibits and Reports on Form 8-K............................... 41
Signature...................................................... 42
2
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,
---------------------------- ---------------------------
2002 2001 2002 2001
----------------- ----------------- --------------- -----------
Revenues
Natural gas sales $ 722,529 $ 411,558 $ 1,185,803 $ 1,047,308
Services 308,045 250,419 569,254 489,162
Product sales and other 60,362 73,778 138,944 227,930
------------- ------------ ----------- -----------
1,090,936 735,755 1,894,001 1,764,400
------------- ------------ ----------- -----------
Costs and Expenses
Gas purchases and other costs of sales 712,476 420,338 1,160,569 1,128,052
Operations and maintenance 98,464 91,174 185,755 186,179
Fuel and power 21,147 16,219 39,531 31,461
Depreciation and amortization 42,623 35,948 83,949 66,023
General and administrative 30,210 20,991 59,742 51,635
Taxes, other than income taxes 13,669 12,489 26,252 24,103
------------- ------------ ----------- -----------
918,589 597,159 1,555,798 1,487,453
------------- ------------ ----------- -----------
Operating Income 172,347 138,596 338,203 276,947
Other Income (Expense)
Earnings from equity investments 24,297 21,147 47,568 42,350
Amortization of excess cost of equity investments (1,394) (2,253) (2,788) (4,506)
Interest, net (43,864) (45,275) (82,886) (95,082)
Other, net 435 (677) 385 (403)
Minority Interest (2,221) (2,633) (5,048) (5,635)
------------- ------------ ------------- ------------
Income Before Income Taxes 149,600 108,905 295,434 213,671
Income Taxes (5,083) (4,679) (9,484) (7,778)
-------------- ------------- -------------- -------------
Net Income $ 144,517 $ 104,226 $ 285,950 $ 205,893
============= ============ ============= ============
General Partner's interest in Net Income $ 65,234 $ 50,606 $ 127,028 $ 92,228
Limited Partners' interest in Net Income 79,283 53,620 158,922 113,665
------------- ------------ ------------- ------------
Net Income $ 144,517 $ 104,226 $ 285,950 $ 205,893
============= ============ ============= ============
Basic Limited Partners' Net Income per Unit $ 0.48 $ 0.36 $ 0.96 $ 0.80
============= =========== ============= ===========
Diluted Limited Partners' Net Income per Unit $ 0.48 $ 0.36 $ 0.95 $ 0.80
============= =========== ============= ===========
Weighted Average Number of Units used in Computation of Limited Partners' Net Income per Unit
Basic 166,589 149,483 166,320 142,300
============= =========== ============= ===========
Diluted 166,761 149,686 166,505 142,493
============= =========== ============= ===========
The accompanying notes are an integral part of these consolidated financial statements.
3
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands)
(Unaudited)
June 30, December 31,
2002 2001
------------- -------------
ASSETS
Current Assets
Cash and cash equivalents $ 32,041 $ 62,802
Accounts and notes receivable
Trade 479,004 215,860
Related parties 40,098 52,607
Inventories
Products 3,369 2,197
Materials and supplies 6,735 6,212
Gas imbalances 38,197 15,265
Gas in underground storage 33,033 18,214
Other current assets 71,624 194,886
----------- -----------
704,101 568,043
----------- -----------
Property, Plant and Equipment, net 5,982,816 5,082,612
Investments 448,110 440,518
Notes receivable 3,029 3,095
Intangibles, net 652,279 563,397
Deferred charges and other assets 115,612 75,001
----------- -----------
TOTAL ASSETS $ 7,905,947 $ 6,732,666
=========== ===========
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Accounts payable
Trade $ 325,971 $ 111,853
Related parties 34,651 9,235
Current portion of long-term debt 802,446 560,219
Accrued interest 43,418 34,099
Deferred revenues 3,726 2,786
Gas imbalances 60,354 34,660
Accrued other liabilities 218,201 209,852
----------- -----------
1,488,767 962,704
----------- -----------
Long-Term Liabilities and Deferred Credits
Long-term debt 2,997,410 2,231,574
Deferred revenues 27,956 29,110
Deferred income taxes 38,525 38,544
Other 234,233 246,464
----------- -----------
3,298,124 2,545,692
----------- -----------
Commitments and Contingencies
Minority Interest 39,010 65,236
----------- -----------
Partners' Capital
Common Units 1,871,905 1,894,677
Class B Units 124,768 125,750
i-Units 1,049,854 1,020,153
General Partner 64,377 54,628
Accumulated other comprehensive income (loss) (30,858) 63,826
------------ -----------
3,080,046 3,159,034
----------- -----------
TOTAL LIABILITIES AND PARTNERS' CAPITAL $ 7,905,947 $ 6,732,666
=========== ===========
The accompanying notes are an integral part of
these consolidated financial statements.
4
Six Months Ended June 30,
-------------------------
2002 2001
----------- ------------
Cash Flows From Operating Activities
Net income $ 285,950 $ 205,893
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization 83,949 66,023
Amortization of excess cost of equity
investments 2,788 4,506
Earnings from equity investments (47,568) (42,350)
Distributions from equity investments 37,259 29,544
Changes in components of working capital (16,302) (36,094)
Other, net (22,441) 54,519
------------ ------------
Net Cash Provided by Operating Activities 323,635 282,041
----------- ------------
Cash Flows From Investing Activities
Acquisitions of assets (816,220) (1,028,403)
Additions to property, plant and equipment
for expansion and maintenance projects (187,290) (109,190)
Sale of investments, property, plant and
equipment, net of removal costs 402 5,711
Contributions to equity investments (6,643) (1,899)
Other 1,152 (5,844)
----------- ------------
Net Cash Used in Investing Activities (1,008,599) (1,139,625)
----------- ------------
Cash Flows From Financing Activities
Issuance of debt 2,123,324 3,209,734
Payment of debt (1,195,306) (3,053,184)
Loans to related party -- (17,100)
Debt issue costs (159) (7,953)
Proceeds from issuance of common units 1,228 833
Proceeds from issuance of i-units -- 996,869
Distributions to partners:
Common units (148,070) (129,128)
Class B units (6,057) (2,790)
General Partner (117,284) (75,134)
Minority interest (4,959) (7,662)
Other, net 1,486 221
----------- ------------
Net Cash Provided by Financing Activities 654,203 914,706
----------- ------------
Increase (Decrease) in Cash and Cash Equivalents (30,761) 57,122
Cash and Cash Equivalents, beginning of period 62,802 59,319
----------- ------------
Cash and Cash Equivalents, end of period $ 32,041 $ 116,441
=========== ============
Noncash Investing and Financing Activities:
Assets acquired by the assumption of
liabilities $ 153,170 $ 257,304
The accompanying notes are an integral part of
these consolidated financial statements.
5
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Organization
General
Unless the context requires otherwise, references to "we", "us", "our" or the
"Partnership" are intended to mean Kinder Morgan Energy Partners, L.P. We have
prepared the accompanying unaudited consolidated financial statements under the
rules and regulations of the Securities and Exchange Commission. Under such
rules and regulations, we have condensed or omitted certain information and
notes normally included in financial statements prepared in conformity with
accounting principles generally accepted in the United States of America. We
believe, however, that our disclosures are adequate to make the information
presented not misleading. The consolidated financial statements reflect all
adjustments that are, in the opinion of our management, necessary for a fair
presentation of our financial results for the interim periods. You should read
these consolidated financial statements in conjunction with our consolidated
financial statements and related notes included in our annual report on Form
10-K for the year ended December 31, 2001.
Critical Accounting Policies and Estimates
Our consolidated financial statements were prepared in accordance with
accounting principles generally accepted in the United States. Certain amounts
included in or affecting our financial statements and related disclosures must
be estimated, requiring us to make certain assumptions with respect to values or
conditions that cannot be known with certainty at the time the financial
statements are prepared.
The preparation of our financial statements in conformity with generally
accepted accounting principles requires our management to make estimates and
assumptions that affect:
o the amounts we report for assets and liabilities;
o our disclosure of contingent assets and liabilities at the date of the
financial statements; and
o the amounts we report for revenues and expenses during the reporting
period.
Therefore, the reported amounts of our assets and liabilities, revenues and
expenses and associated disclosures with respect to contingent assets and
obligations are necessarily affected by these estimates. We evaluate these
estimates on an ongoing basis, utilizing historical experience, consultation
with experts and other methods we consider reasonable in the particular
circumstances. Nevertheless, actual results may differ significantly from our
estimates. Any effects on our business, financial position or results of
operations resulting from revisions to these estimates are recorded in the
period in which the facts that give rise to the revision become known.
In preparing our financial statements and related disclosures, we must use
estimates in determining the economic useful lives of our assets, provisions for
uncollectible accounts receivable, exposures under contractual indemnifications
and various other recorded or disclosed amounts. However, we believe that
certain accounting policies are of more significance in our financial statement
preparation process than others. With respect to our environmental exposure, we
utilize both internal staff and external experts to assist us in identifying
environmental issues and in estimating the costs and timing of remediation
efforts. Often, as the remediation evaluation and effort progresses, additional
information is obtained, requiring revisions to estimated costs. In addition, we
are subject to litigation as the result of our business operations and
transactions. We utilize both internal and external counsel in evaluating our
potential exposure to adverse outcomes from judgments or settlements. To the
extent that actual outcomes differ from our estimates, or additional facts and
circumstances cause us to revise our estimates, our earnings will be affected.
These revisions are reflected in our income in the period in which they are
reasonably determinable.
Net Income Per Unit
We compute Basic Limited Partners' Net Income per Unit by dividing our
limited partners' interest in net income by the weighted average number of units
outstanding during the period. Diluted Limited Partners' Net Income per Unit
reflects the potential dilution, by application of the treasury stock method,
that could occur if options to issue units were exercised, which would result in
the issuance of additional units that would then share in our net income.
6
2. Acquisitions and Joint Ventures
During the first six months of 2002, we completed the following acquisitions.
Each of the acquisitions was accounted for under the purchase method and the
assets acquired and liabilities assumed were recorded at their estimated fair
market values as of the acquisition date. The preliminary amounts assigned to
assets and liabilities may be adjusted during a short period following the
acquisition. The results of operations from these acquisitions are included in
the consolidated financial statements from the effective date of acquisition.
Cochin Pipeline
In January 2002, we purchased an additional 10% ownership interest in the
Cochin Pipeline System from NOVA Chemicals Corporation for approximately $29
million in cash. We now own approximately 44.8% of the Cochin Pipeline System.
The transaction was effective December 31, 2001, and we allocated the purchase
price to property, plant and equipment in January 2002. We record our
proportional share of joint venture revenues and expenses and cost of joint
venture assets with respect to the Cochin Pipeline System as part of our
Products Pipelines business segment.
Laser Materials Services LLC
Effective January 1, 2002, we acquired all of the equity interests of Laser
Materials Services LLC for approximately $8.9 million and the assumption of
approximately $3.3 million of liabilities, including long-term debt of $0.4
million. Laser Materials Services LLC operates 59 transload facilities in 18
states. The facilities handle dry-bulk products, including aggregates, plastics
and liquid chemicals. The acquisition of Laser Materials Services LLC expanded
our growing terminal operations and is part of our Terminals business segment.
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $ 8,916
Debt assumed 357
Liabilities assumed 2,967
------
Total purchase price $12,240
=======
Allocation of purchase price:
Current assets $ 879
Property, plant and equipment 11,361
-------
$12,240
=======
International Marine Terminals
Effective January 1, 2002, we acquired a 33 1/3% interest in International
Marine Terminals from Marine Terminals Incorporated. Effective February 1, 2002,
we acquired an additional 33 1/3% interest in IMT from Glenn Springs Holdings,
Inc. Our combined purchase price was approximately $40.5 million, including the
assumption of $40 million of long-term debt. IMT is a partnership that operates
a bulk terminal site in Port Sulphur, Louisiana. The Port Sulphur terminal is a
multi-purpose import and export facility, which handles approximately 7 million
tons annually of bulk products including coal, petroleum coke and iron ore. The
acquisition complements our existing bulk terminal assets, and we include IMT as
part of our Terminals business segment.
Our purchase price and our allocation to assets acquired, liabilities assumed
and minority interest was as follows (in thousands):
Purchase price:
Cash received, net of transaction costs $(3,781)
Debt assumed 40,000
Liabilities assumed 4,249
-------
Total purchase price $40,468
=======
Allocation of purchase price:
Current assets $6,600
Property, plant and 31,781
equipment
Deferred charges and other assets 139
Minority interest 1,948
-------
$40,468
=======
7
Kinder Morgan Tejas
Effective January 31, 2002, we acquired all of the equity interests of Tejas
Gas, LLC, a wholly-owned subsidiary of InterGen (North America), Inc., for
approximately $726.7 million and the assumption of approximately $103.8 million
of liabilities. As of June 30, 2002, we have paid $688.2 million and established
a $37.6 million reserve for a final working capital settlement payment. We made
a final working capital settlement payment of $38.4 million in July 2002.
Tejas Gas, LLC is primarily comprised of a 3,400-mile natural gas intrastate
pipeline system that extends from south Texas along the Mexico border and the
Texas Gulf Coast to near the Louisiana border and north from near Houston to
east Texas. The acquisition expands our natural gas operations within the State
of Texas. The acquired assets are referred to as Kinder Morgan Tejas in this
report and are included in our Natural Gas Pipelines business segment.
The allocation of our purchase price to the assets and liabilities of Kinder
Morgan Tejas is preliminary, pending minor purchase price adjustments. It was
based on an independent appraisal of fair market values as follows (in
thousands):
Purchase price:
Cash paid, including transaction $726,655
costs
Liabilities assumed 103,787
--------
Total purchase price $830,442
========
Allocation of purchase price:
Current assets $ 72,610
Property, plant and equipment,
incl cushion 688,769
Goodwill 69,063
--------
$830,442
========
The $69.1 million of goodwill was assigned to our Natural Gas Pipelines
business segment and the entire amount is expected to be deductible for tax
purposes.
Trailblazer Pipeline Company
On December 12, 2001, we announced that we had signed a definitive agreement
to acquire the remaining 33 1/3% ownership interest in Trailblazer Pipeline
Company from Enron Trailblazer Pipeline Company for $68 million in cash. We
closed the transaction on May 6, 2002 and we now own 100% of Trailblazer
Pipeline Company. During the first quarter of 2002, we paid $12.0 million to CIG
Trailblazer Gas Company, an affiliate of El Paso Corporation, in exchange for
CIG's relinquishment of its rights to become a 7% to 8% equity owner in
Trailblazer Pipeline Company in mid-2002.
Our purchase price and our allocation to assets acquired, liabilities assumed
and minority interest was as follows (in thousands):
Purchase price:
Cash paid, including costs $ 80,125
--------
Total purchase price $ 80,125
========
Allocation of purchase price:
Property, plant and equipment $ 41,409
Goodwill 15,000
Minority interest 23,716
--------
$ 80,125
========
The $15.0 million of goodwill was assigned to our Natural Gas Pipelines
business segment and the entire amount is expected to be deductible for tax
purposes.
Milwaukee Bagging Operations
Effective May 1, 2002, we purchased a bagging operation facility adjacent to
our Milwaukee, Wisconsin dry-bulk terminal for $8.5 million. The purchase
enhances the operations at our Milwaukee terminal, which is capable of handling
up to 150,000 tons per year of fertilizer and salt for de-icing and livestock
purposes. The Milwaukee bagging operations are included in our Terminals
business segment.
8
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $ 8,500
--------
Total purchase price $ 8,500
========
Allocation of purchase price:
Current assets $ 40
Property, plant and equipment 3,140
Goodwill 5,320
--------
$ 8,500
========
The $5.3 million of goodwill was assigned to our Terminals business segment
and the entire amount is expected to be deductible for tax purposes.
Pro Forma Information
The following summarized unaudited Pro Forma Consolidated Income Statement
information for the six months ended June 30, 2002 and 2001, assumes all of the
acquisitions we have made since January 1, 2001, including the ones listed
above, had occurred as of January 1, 2001. We have prepared these unaudited Pro
Forma financial results for comparative purposes only. These unaudited Pro Forma
financial results may not be indicative of the results that would have occurred
if we had completed these acquisitions as of January 1, 2001 or the results that
will be attained in the future. Amounts presented below are in thousands, except
for the per unit amounts:
Pro Forma
Six Months Ended
June 30,
2002 2001
---- ----
(Unaudited)
Revenues $2,136,649 $3,756,445
Operating Income 343,469 326,274
Net Income 294,461 269,514
Basic and diluted Limited Partners' Net Income $ 1.00 $ 0.85
per unit
3. Litigation and Other Contingencies
Federal Energy Regulatory Commission Proceedings
SFPP, L.P.
SFPP, L.P. is the subsidiary limited partnership that owns our Pacific
operations, excluding the CALNEV pipeline and related terminals acquired from
GATX Corporation. 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. The Federal Energy Regulatory
Commission complaints seek approximately $137 million in tariff refunds and
approximately $22 million in prospective annual tariff reductions.
OR92-8, et al. proceedings. In September 1992, El Paso Refinery, L.P.
filed a protest/complaint with the FERC:
o challenging SFPP's East Line rates from El Paso, Texas to Tucson and
Phoenix, Arizona;
o challenging SFPP's proration policy; and
o seeking to block the reversal of the direction of flow of SFPP's
six-inch pipeline between Phoenix and Tucson.
At various subsequent dates, the following other shippers on SFPP's South
System filed separate complaints, and/or motions to intervene in the FERC
proceeding, challenging SFPP's rates on its East and/or West Lines:
o Chevron U.S.A. Products Company;
o Navajo Refining Company;
o ARCO Products Company;
o Texaco Refining and Marketing Inc.;
9
o Refinery Holding Company, L.P. (a partnership formed by El Paso Refinery's
long-term secured creditors that purchased its refinery in May 1993);
o Mobil Oil Corporation; and
o Tosco Corporation.
Certain of these parties also claimed that a gathering enhancement fee at SFPP's
Watson Station in Carson, California was charged in violation of the Interstate
Commerce Act.
The FERC consolidated these challenges in Docket Nos. OR92-8-000, et al., and
ruled that they are complaint proceedings, with the burden of proof on the
complaining parties. These parties must show that SFPP's rates and practices at
issue violate the requirements of the Interstate Commerce Act.
A FERC administrative law judge held hearings in 1996, and issued an initial
decision on September 25, 1997. The initial decision agreed with SFPP's position
that "changed circumstances" had not been shown to exist on the West Line, and
therefore held that all West Line rates that were "grandfathered" under the
Energy Policy Act of 1992 were deemed to be just and reasonable and were not
subject to challenge, either for the past or prospectively, in the Docket No.
OR92-8 et al. proceedings. SFPP's Tariff No. 18 for movement of jet fuel from
Los Angeles to Tucson, which was initiated subsequent to the enactment of the
Energy Policy Act, was specifically excepted from that ruling.
The initial decision also included rulings generally adverse to SFPP on such
cost of service issues as:
o the capital structure to be used in computing SFPP's 1985 starting rate
base ;
o the level of income tax allowance; and
o the recovery of civil and regulatory litigation expenses and certain
pipeline reconditioning costs.
The administrative law judge also ruled that SFPP's gathering enhancement
service at Watson Station was subject to FERC jurisdiction and ordered SFPP to
file a tariff for that service, with supporting cost of service documentation.
SFPP and other parties asked the Commission to modify various rulings made in
the initial decision. On January 13, 1999, the FERC issued its Opinion No. 435,
which affirmed certain of those rulings and reversed or modified others.
With respect to SFPP's West Line, the FERC affirmed that all but one of the
West Line rates are "grandfathered" as just and reasonable and that "changed
circumstances" had not been shown to satisfy the complainants' threshold burden
necessary to challenge those rates. The FERC further held that the rate stated
in Tariff No. 18 did not require rate reduction. Accordingly, the FERC dismissed
all complaints against the West Line rates without any requirement that SFPP
reduce, or pay any reparations for, any West Line rate.
With respect to the East Line rates, Opinion No. 435 made several changes in
the initial decision's methodology for calculating the rate base. It held that
the June 1985 capital structure of SFPP's parent company at that time, rather
than SFPP's 1988 partnership capital structure, should be used to calculate the
starting rate base and modified the accumulated deferred income tax and
allowable cost of equity used to calculate the rate base. It also ruled that
SFPP would not owe reparations to any complainant for any period prior to the
date on which that complainant's complaint was filed, thus reducing by two years
the potential reparations period claimed by most complainants.
SFPP and certain complainants sought rehearing of Opinion No. 435 by the
FERC. In addition, ARCO, RHC, Navajo, Chevron and SFPP filed petitions for
review of Opinion No. 435 with the U.S. Court of Appeals for the District of
Columbia Circuit, all of which were either dismissed as premature or held in
abeyance pending FERC action on the rehearing requests.
On March 15, 1999, as required by the FERC's order, SFPP submitted a
compliance filing implementing the rulings made in Opinion No. 435, establishing
the level of rates to be charged by SFPP in the future, and setting forth the
amount of reparations that would be owed by SFPP to the complainants under the
order. The complainants contested SFPP's compliance filing.
On May 17, 2000, the FERC issued its Opinion No. 435-A, which modified
Opinion No. 435 in certain respects. It denied requests to reverse its rulings
that SFPP's West Line rates and Watson Station gathering enhancement facilities
fee are entitled to be treated as "grandfathered" rates under the Energy Policy
Act. It suggested, however, that if SFPP had fully recovered the capital costs
of the gathering enhancement facilities, that might form the basis of an amended
"changed circumstances" complaint.
10
Opinion No. 435-A granted a request by Chevron and Navajo to require that
SFPP's December 1988 partnership capital structure be used to compute the
starting rate base from December 1983 forward, as well as a request by SFPP to
vacate a ruling that would have required the elimination of approximately $125
million from the rate base used to determine capital structure. It also granted
two clarifications sought by Navajo, to the effect that SFPP's return on its
starting rate base should be based on SFPP's capital structure in each given
year (rather than a single capital structure from the outset) and that the
return on deferred equity should also vary with the capital structure for each
year. Opinion No. 435-A denied the request of Chevron and Navajo that no income
tax allowance be recognized for the limited partnership interests held by SFPP's
corporate parent, as well as SFPP's request that the tax allowance should
include interests owned by certain non-corporate entities. However, it granted
Navajo's request to make the computation of interest expense for tax allowance
purposes the same as for debt return.
Opinion No. 435-A reaffirmed that SFPP may recover certain litigation costs
incurred in defense of its rates (amortized over five years), but reversed a
ruling that those expenses may include the costs of certain civil litigation
with Navajo and El Paso. It also reversed a prior decision that litigation costs
should be allocated between the East and West Lines based on throughput, and
instead adopted SFPP's position that such expenses should be split equally
between the two systems.
As to reparations, Opinion No. 435-A held that no reparations would be
awarded to West Line shippers and that only Navajo was eligible to recover
reparations on the East Line. It reaffirmed that a 1989 settlement with SFPP
barred Navajo from obtaining reparations prior to November 23, 1993, but allowed
Navajo reparations for a one-month period prior to the filing of its December
23, 1993 complaint. Opinion No. 435-A also confirmed that FERC's indexing
methodology should be used in determining rates for reparations purposes and
made certain clarifications sought by Navajo.
Opinion No. 435-A denied Chevron's request for modification of SFPP's
prorationing policy. That policy required customers to demonstrate a need for
additional capacity if a shortage of available pipeline space existed. SFPP's
prorationing policy has since been changed to eliminate the "demonstrated need"
test.
Finally, Opinion No. 435-A directed SFPP to revise its initial compliance
filings to reflect the modified rulings. It eliminated the refund obligation for
the compliance tariff containing the Watson Station gathering enhancement fee,
but required SFPP to pay refunds to the extent that the initial compliance
tariff East Line rates exceeded the rates produced under Opinion No. 435-A.
In June 2000, several parties filed requests for rehearing of rulings made in
Opinion No. 435-A. Chevron and RHC both sought reconsideration of the FERC's
ruling that only Navajo is entitled to reparations for East Line shipments. SFPP
sought rehearing of the FERC's:
o decision to require use of the December 1988 partnership capital
structure for the period 1984-88 in computing the starting rate base;
o elimination of civil litigation costs;
o refusal to allow any recovery of civil litigation settlement payments;
and
o failure to provide any allowance for regulatory expenses in prospective
rates.
On July 17, 2000, SFPP submitted a compliance filing implementing the rulings
made in Opinion No. 435-A, together with a calculation of reparations due to
Navajo and refunds due to other East Line shippers. SFPP also filed a tariff
stating revised East Line rates based on those rulings.
ARCO, Chevron, Navajo, RHC, Texaco and SFPP sought judicial review of
Opinion No. 435-A in the U.S. Court of Appeals for the District of Columbia
Circuit. All of those petitions except Chevron's were either dismissed as
premature or held in abeyance pending action on the rehearing requests. On
September 19, 2000, the court dismissed Chevron's petition for lack of
prosecution, and subsequently denied a motion by Chevron for reconsideration of
that dismissal.
On September 13, 2001, the FERC issued Opinion No. 435-B, which ruled on
requests for rehearing and comments on SFPP's compliance filing. Based on those
rulings, the FERC directed SFPP to submit a further revised compliance filing,
including revised tariffs and revised estimates of reparations and refunds.
Opinion No. 435-B denied SFPP's requests for rehearing, which involved the
capital structure to be used in computing starting rate base, SFPP's ability
to recover litigation and settlement costs incurred in connection with the
11
Navajo and El Paso civil litigation, and the provision for regulatory costs in
prospective rates. However, it modified the Commission's prior rulings on
several other issues. It reversed the ruling that only Navajo is eligible to
seek reparations, holding that Chevron, RHC, Tosco and Mobil are also eligible
to recover reparations for East Line shipments. It ruled, however, that Ultramar
is not eligible for reparations in the Docket No. OR92-8 et al. proceedings .
The FERC also changed prior rulings that had permitted SFPP to use certain
litigation, environmental and pipeline rehabilitation costs that were not
recovered through the prescribed rates to offset overearnings (and potential
reparations) and to recover any such costs that remained by means of a surcharge
to shippers. Opinion No. 435-B required SFPP to pay reparations to each
complainant without any offset for unrecovered costs. It required SFPP to
subtract from the total 1995-1998 supplemental costs allowed under Opinion No.
435-A any overearnings not paid out as reparations, and allowed SFPP to recover
any remaining costs from shippers by means of a five-year surcharge beginning
August 1, 2000. Opinion No. 435-B also ruled that SFPP would only be permitted
to recover certain regulatory litigation costs through the surcharge, and that
the surcharge could not include environmental or pipeline rehabilitation costs.
Opinion No. 435-B directed SFPP to make additional changes in its revised
compliance filing, including:
o using a remaining useful life of 16.8 years in amortizing its starting
rate base, instead of 20.6 years;
o removing the starting rate base component from base rates as of August
1, 2001;
o amortizing the accumulated deferred income tax balance beginning in
1992, rather than 1988;
o listing the corporate unitholders that were the basis for the income tax
allowance in its compliance filing and certifying that those companies are
not Subchapter S corporations; and
o "clearly" excluding civil litigation costs and explaining how it limited
litigation costs to FERC-related expenses and assigned them to appropriate
periods in making reparations calculations.
On October 15, 2001, Chevron and RHC filed petitions for rehearing of
Opinion No. 435-B. Chevron asked the FERC to clarify:
o the period for which Chevron is entitled to reparations; and
o whether East Line shippers that have received the benefit of
Commission-prescribed rates for 1994 and subsequent years must show that
there has been a substantial divergence between the cost of service and
the change in the Commission's rate index in order to have standing to
challenge SFPP rates for those years in pending or subsequent proceedings.
RHC's petition contended that Opinion No. 435-B should be modified on
rehearing, to the extent it:
o suggested that a "substantial divergence" standard applies to complaint
proceedings challenging the total level of SFPP's East Line rates
subsequent to the Docket No. OR92-8 et al. proceedings;
-- ---
o required a substantial divergence to be shown between SFPP's cost of
service and the change in the FERC oil pipeline index in such subsequent
complaint proceedings, rather than a substantial divergence between the
cost of service and SFPP's revenues; and
o permitted SFPP to recover 1993 rate case litigation expenses through a
surcharge mechanism.
ARCO, Ultramar and SFPP filed petitions for review of Opinion No. 435-B (and
in SFPP's case, Opinion Nos. 435 and 435-A) in the U.S. Court of Appeals for the
District of Columbia Circuit. The court consolidated the Ultramar and SFPP
petitions with the consolidated cases held in abeyance and ordered that the
consolidated cases be returned to its active docket.
On November 7, 2001, the FERC issued an order ruling on the petitions for
rehearing of Opinion No. 435-B. The Commission held that Chevron's eligibility
for reparations should be measured from August 3, 1993, rather than the
September 23, 1992 date sought by Chevron. The Commission also clarified its
prior ruling with respect to the "substantial divergence" test, holding that in
order to be considered on the merits, complaints challenging the SFPP rates set
by applying the Commission's indexing regulations to the 1994 cost of service
derived under the Opinion No. 435 orders must demonstrate a substantial
divergence between the indexed rates and the pipeline's actual cost of service.
Finally, the FERC held that SFPP's 1993 regulatory costs should not be included
in the surcharge for the recovery of supplemental costs.
On December 7, 2001, Chevron filed a petition for rehearing of the FERC's
November 7, 2001 order. The petition requested the Commission to specify whether
Chevron would be entitled to reparations for the two year period prior to the
August 3, 1993 filing of its complaint.
12
On January 7, 2002, SFPP and RHC filed petitions for review of the FERC's
November 7, 2001 order in the U.S. Court of Appeals for the District of Columbia
Circuit. On January 8, 2002, the court consolidated those petitions with the
petitions for review of Opinion Nos. 435, 435-A and 435-B. On January 24, 2002,
the court ordered the consolidated proceedings to be held in abeyance until the
FERC acts on Chevron's request for rehearing of the November 7, 2001 order.
SFPP submitted its compliance filing and tariffs implementing Opinion No.
435-B and the Commission's November 7, 2001 order on November 20, 2001. Motions
to intervene and protest were subsequently filed by ARCO, Mobil (which now
submits filings under the name ExxonMobil), RHC, Navajo and Chevron, alleging
that SFPP:
o should have calculated the supplemental cost surcharge differently;
o did not provide adequate information on the taxpaying status of its
unitholders; and
o failed to estimate potential reparations for ARCO.
On December 10, 2001, SFPP filed a response to those claims. On December 14,
2001, SFPP filed a revised compliance filing and new tariff correcting an error
that had resulted in understating the proper surcharge and tariff rates.
On December 20, 2001, the FERC's Director of the Division of Tariffs and
Rates Central issued two letter orders rejecting SFPP's November 20, 2001 and
December 14, 2001 tariff filings because they were not made effective
retroactive to August 1, 2000. On January 11, 2002, SFPP filed a request for
rehearing of those orders by the Commission, on the ground that the FERC has no
authority to require retroactive reductions of rates filed pursuant to its
orders in complaint proceedings.
Motions to intervene and protest the December 14, 2001 corrected submissions
were filed by Navajo, ARCO and ExxonMobil. Ultramar requested leave to file an
out-of-time intervention and protest of both the November 20, 2001 and December
14, 2001 submissions. On January 14, 2002, SFPP responded to those filings to
the extent they were not mooted by the orders rejecting the tariffs in question.
On February 15, 2002, the Commission denied rehearing of the Director of the
Division of Tariffs and Rates Central's letter orders. On February 21, 2002,
SFPP filed a motion requesting that the Commission clarify whether it intended
SFPP to file a retroactive tariff or simply make a compliance filing calculating
the effects of Opinion No. 435-B back to August 1, 2000; in the event the order
was clarified to require a retroactive tariff filing, SFPP asked the Commission
to stay that requirement pending judicial review.
On April 8, 2002, SFPP filed a petition for review of the Commission's
February 15, 2002 Order in the U.S. Court of Appeals for the District of
Columbia Circuit. BP West Coast Products, LLC (formerly ARCO); ExxonMobil; Tosco
Corporation; and Ultramar, Inc. and Valero Energy Corporation filed motions to
intervene in that proceeding. On April 9, 2002, the Court of Appeals
consolidated SFPP's petition with the petitions for review of the Commission's
prior orders and directed the parties "to file motions to govern future
proceedings" by May 9, 2002. Motions were filed by SFPP, RHC, Navajo, Chevron
and the "Indicated Parties" (BP West Coast Products, ExxonMobil, Ultramar and
Tosco). The FERC requested that the Court continue to hold the consolidated
cases in abeyance pending the completion of proceedings before the agency on
rehearing.
On June 25, 2002, the Court granted the ExxonMobil and Valero Energy motions
to intervene, and directed intervenors on the side of petitioners to notify the
court of that status and provide a statement of issues to be raised. ExxonMobil
filed a notice on July 2, 2002; Ultramar, Inc. and Valero Energy on July 10,
2002. On July 12, 2002, SFPP responded to the ExxonMobil notice in order to urge
the Court not to rely on ExxonMobil's categorization of the issues and party
alignments in allocating briefing.
On May 31, 2002, SFPP filed FERC Tariff No. 70, which implemented the
FERC's annual indexing adjustment. Motions to intervene and protest were filed
by Navajo and Chevron, contesting any indexing adjustment to the litigation
surcharge permitted by Opinion No. 435-B. On June 28, 2002, the FERC's Director
of the Division of Tariffs and Rates rejected Tariff No. 70 on the ground that
the surcharge should not be indexed. On July 2, 2002, SFPP filed FERC Tariff No.
73 to replace Tariff No. 70 in compliance with that decision, which resulted in
an average reduction from Tariff No. 70 of approximately $.0002 per barrel.
Sepulveda proceedings. In December 1995, Texaco filed a complaint at FERC
(Docket No. OR96-2) alleging that movements on SFPP's Sepulveda pipelines (Line
Sections 109 and 110) to Watson Station, in the Los Angeles
13
basin, were subject to FERC's jurisdiction under the Interstate Commerce Act,
and, if so, claimed that the rate for that service was unlawful. Texaco sought
to have its claims addressed in the OR92-8 proceeding discussed above. Several
other West Line shippers filed similar complaints and/or motions to intervene.
The Commission consolidated all of these filings into Docket Nos. OR96-2 and set
the claims for a separate hearing. A hearing before an administrative law judge
was held in December 1996.
In March 1997, the judge issued an initial decision holding that the
movements on the Sepulveda pipelines were not subject to FERC jurisdiction. On
August 5, 1997, the FERC reversed that decision. On October 6, 1997, SFPP filed
a tariff establishing the initial interstate rate for movements on the Sepulveda
pipelines at the preexisting rate of five cents per barrel. Several shippers
protested that rate. In December 1997, SFPP filed an application for authority
to charge a market-based rate for the Sepulveda service, which application was
protested by several parties. On September 30, 1998, the FERC issued an order
finding that SFPP lacks market power in the Watson Station destination market
and that, while SFPP appeared to lack market power in the Sepulveda origin
market, a hearing was necessary to permit the protesting parties to substantiate
allegations that SFPP possesses market power in the origin market. A hearing
before a FERC administrative law judge on this limited issue was held in
February 2000.
On December 21, 2000, the FERC administrative law judge issued his initial
decision finding that SFPP possesses market power over the Sepulveda origin
market. The ultimate disposition of SFPP's application is pending before the
FERC.
Following the issuance of the initial decision in the Sepulveda case, the
FERC judge indicated an intention to proceed to consideration of the justness
and reasonableness of the existing rate for service on the Sepulveda pipelines.
On February 22, 2001, the FERC granted SFPP's motion to block such consideration
and to defer consideration of the pending complaints against the Sepulveda rate
until after FERC's final disposition of SFPP's market rate application.
OR97-2; OR98-1. et al. In October 1996, Ultramar filed a complaint at FERC
(Docket No. OR97-2) challenging SFPP's West Line rates, claiming they were
unjust and unreasonable and no longer subject to grandfathering. In October
1997, ARCO, Mobil and Texaco filed a complaint at the FERC (Docket No. OR98-1)
challenging the justness and reasonableness of all of SFPP's interstate rates,
raising claims against SFPP's East and West Line rates similar to those that
have been at issue in Docket Nos. OR92-8, et al., but expanding them to include
challenges to SFPP's grandfathered interstate rates from the San Francisco Bay
area to Reno, Nevada and from Portland to Eugene, Oregon - the North Line and
Oregon Line. In November 1997, Ultramar Diamond Shamrock Corporation filed a
similar, expanded complaint (Docket No. OR98-2). Tosco Corporation filed a
similar complaint in April 1998. The shippers seek both reparations and
prospective rate reductions for movements on all of the lines. SFPP answered
each of these complaints. FERC issued orders accepting the complaints and
consolidating them into one proceeding (Docket No. OR96-2, et al.), but holding
them in abeyance pending a FERC decision on review of the initial decision in
Docket Nos. OR92-8, et al.
In a companion order to Opinion No. 435, the FERC gave the complainants an
opportunity to amend their complaints in light of Opinion No. 435, which the
complainants did in January 2000. On May 17, 2000, the FERC issued an order
finding that the various complaining parties had alleged sufficient grounds for
their complaints to go forward to a hearing to assess whether any of the
challenged rates that are grandfathered under the Energy Policy Act will
continue to have such status and, if the grandfathered status of any rate is not
upheld, whether the existing rate is just and reasonable.
In August 2000, Navajo and RHC filed complaints against SFPP's East Line
rates and Ultramar filed an additional complaint updating its pre-existing
challenges to SFPP's interstate pipeline rates. In September 2000, FERC accepted
these new complaints and consolidated them with the ongoing proceeding in Docket
No. OR96-2, et al.
A hearing in this consolidated proceeding was held from October 2001 to March
2002. An initial decision by the administrative law judge is expected in the
latter half of 2002.
The complainants have alleged a variety of grounds for finding "substantially
changed circumstances." Applicable rules and regulations in this field are
vague, relevant factual issues are complex, and there is little precedent
available regarding the factors to be considered or the method of analysis to be
employed in making a determination of "substantially changed circumstances,"
which is the showing necessary to render "grandfathered" rates subject to
challenge. Given the newness of the grandfathering standard under the Energy
Policy Act and limited precedent, we cannot predict how these allegations will
be viewed by the FERC.
14
If "substantially changed circumstances" are found, SFPP rates previously
"grandfathered" under the Energy Policy Act will lose their "grandfathered"
status. If these rates are found to be unjust and unreasonable, shippers may be
entitled to a prospective rate reduction and a complainant may be entitled to
reparations for periods from the date of its complaint to the date of the
implementation of the new rates.
We are not able to predict with certainty the final outcome of the FERC
proceedings involving SFPP, should they be carried through to their conclusion,
or whether we can reach a settlement with some or all of the complainants.
Although it is possible that current or future proceedings could be resolved in
a manner adverse to us, we believe that the resolution of such matters will not
have a material adverse effect on our business, financial position or results of
operations.
CALNEV Pipe Line LLC
We acquired CALNEV Pipe Line LLC in March 2001. CALNEV provides interstate
and intrastate transportation from an interconnection with SFPP at Colton,
California to destinations in and around Las Vegas, Nevada.
OR01-08. In August 2001, ARCO filed a complaint against CALNEV's interstate
rates alleging that they were unjust and unreasonable. Tosco and Ultramar filed
interventions and subsequently filed complaints. In October 2001, the Commission
set the ARCO claim for investigation and hearing. The matter was first referred
to a settlement judge. On November 14, 2001, CALNEV filed a motion for rehearing
or, in the alternative, clarification of the Commission's October 2001 order.
CALNEV asserted that the Commission should have dismissed ARCO's complaint
because it did not meet the standards of the Commission's regulations or, in the
alternative, that the Commission should clarify the standards of pleading and
proof applicable to ARCO's complaint.
In April 2002, CALNEV and the complainants were able to reach a mutually
agreeable resolution of the disputed claims, and a settlement agreement was
executed. In the settlement agreement, the parties agreed, among other things,
that for a period of five years CALNEV would not seek a rate increase at the
FERC or the California Public Utiltiies Commission except as permitted under
four specific exceptions and that the complainants would not file complaints
against CALNEV's rates, provided it complies with such exceptions. On May 21,
2002, the FERC granted the parties' joint motion to dismiss the three pending
complaints with prejudice and accepted CALNEV's withdrawal of its pending
request for rehearing.
ORO2-9. In April 2002, Chevron filed a complaint against CALNEV's interstate
rates, making allegations of unjust and unreasonable rates that were
substantially similar to those alleged by ARCO, Ultramar and Tosco in the OR01-8
docket. CALNEV answered Chevron's complaint on May 16, 2002, and Chevron moved
for leave to respond to CALNEV's answer on June 17, 2002. The Commission has yet
to rule on Chevron's motion or response and has not yet set Chevron's complaint
for investigation and hearing. CALNEV and Chevron have reached a settlement in
principle and are currently negotiating the details of a settlement agreement.
We are not able to predict with certainty the final outcome of the FERC
proceedings involving CALNEV, 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.
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.
15
On March 16, 2000, SFPP filed an application with the CPUC seeking authority
to justify its rates for intrastate transportation of refined petroleum products
on competitive, market-based conditions rather than on traditional,
cost-of-service analysis.
On April 10, 2000, ARCO and Mobil filed a new complaint with the CPUC
asserting that SFPP's California intrastate rates are not just and reasonable
based on a 1998 test year and requesting the CPUC to reduce SFPP's rates
prospectively. The amount of the reduction in SFPP rates sought by the
complainants is not discernible from the complaint.
The rehearing complaint was heard by the CPUC in October 2000 and the April
2000 complaint and SFPP's market-based application were heard by the CPUC in
February 2001. All three matters stand submitted as of April 13, 2001, and a
decision addressing the submitted matters is expected within three to four
months.
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 claims that the rent payable for each
of the years 1994 through 2004 should be approximately $4.4 million and SPTC
claims it should be approximately $15.0 million. We believe SPTC's position in
this case is without merit and we have set aside reserves that we believe are
adequate to address any reasonably foreseeable outcome of this matter. We expect
this matter to go to trial during the third quarter of 2002.
FERC Order 637
Kinder Morgan Interstate Gas Transmission LLC
On June 15, 2000, Kinder Morgan Interstate Gas Transmission LLC made its
filing to comply with FERC's Orders 637 and 637-A. That filing contained KMIGT's
compliance plan to implement the changes required by FERC dealing with the way
business is conducted on interstate natural gas pipelines. All interstate
natural gas pipelines were required to make such compliance filings, according
to a schedule established by FERC. From October 2000 through June 2001, KMIGT
held a series of technical and phone conferences to identify issues, obtain
input, and modify its Order 637 compliance plan, based on comments received from
FERC Staff and other interested parties and shippers. On June 19, 2001, KMIGT
received a letter from FERC encouraging it to file revised pro-forma tariff
sheets, which reflected the latest discussions and input from parties into its
Order 637 compliance plan. KMIGT made such a revised Order 637 compliance filing
on July 13, 2001. The July 13, 2001 filing contained little substantive change
from the original pro-forma tariff sheets that KMIGT originally proposed on June
15, 2000. On October 19, 2001, KMIGT received an order from FERC, addressing its
July 13, 2001 Order 637 compliance plan. In the Order addressing the July 13,
2001 compliance plan, KMIGT's plan was accepted, but KMIGT was directed to make
several changes to its tariff, and in doing so, was directed that it could not
place the revised tariff into effect until further order of the Commission.
KMIGT filed its compliance filing with the October 19, 2001 Order on November
19, 2001 and also filed a request for rehearing/clarification of the FERC's
October 19, 2001 Order on November 19, 2001. The November 19, 2001 Compliance
filing has been protested by several parties. KMIGT filed responses to those
protests on December 14, 2001. At this time, it is unknown when this proceeding
will be finally resolved. KMIGT currently expects that it may not have a fully
compliant Order 637 tariff approved and in effect until sometime in the third
quarter of 2002. The full impact of implementation of Order 637 on the KMIGT
system is under evaluation. We believe that these matters will not have a
material adverse effect on our business, financial position or results of
operations.
Separately, numerous petitioners, including KMIGT, have filed appeals of
Order 637 in the D.C. Circuit, potentially raising a wide array of issues
related to Order 637 compliance. Initial briefs were filed on April 6, 2001,
addressing issues contested by industry participants. Oral arguments on the
appeals were held before the courts in
16
December 2001. On April 5, 2002, the D.C. Circuit issued an order largely
affirming Order Nos. 637, et seq. The D.C. Circuit remanded the Commission's
decision to impose a 5-year cap on bids that an existing shipper would have to
match in the right of first refusal process. The D.C. Circuit also remanded the
Commission's decision to allow forward-hauls and backhauls to the same point.
Finally, the D.C. Circuit held that several aspects of the Commission's
segmentation policy and its policy on discounting at alternate points were not
ripe for review. The FERC has requested comments from the industry with respect
to the issues remanded by the D.C. Circuit. They were due July 30, 2002.
Trailblazer Pipeline Company
On August 15, 2000, Trailblazer Pipeline Company made a filing to comply with
FERC's Order Nos. 637 and 637-A. Trailblazer's compliance filing reflected
changes in:
o segmentation;
o scheduling for capacity release transactions;
o receipt and delivery point rights;
o treatment of system imbalances;
o operational flow orders;
o penalty revenue crediting; and
o right of first refusal language.
On October 15, 2001, FERC issued its order on Trailblazer's Order No. 637
compliance filing. FERC approved Trailblazer's proposed language regarding
operational flow orders and the right of first refusal, but is requiring
Trailblazer to make changes to its tariff related to the other issues listed
above. Most of the tariff provisions will have an effective date of January 1,
2002, with the exception of language related to scheduling and segmentation,
which will become effective at a future date dependent on when KMIGT's Order
No. 637 provisions go into effect. Trailblazer anticipates no adverse impact on
its business as a result of the implementation of Order No. 637.
On November 14, 2001, Trailblazer made its compliance filing pursuant to the
FERC order of October 15, 2001. That compliance filing has been protested.
Separately, also on November 14, 2001, Trailblazer filed for rehearing of that
FERC order. These pleadings are pending FERC action.
Standards of Conduct Rulemaking
On September 27, 2001, FERC issued a Notice of Proposed Rulemaking in
Docket No. RM01-10 in which it proposed new rules governing the interaction
between an interstate natural gas pipeline and its affiliates. If adopted as
proposed, the Notice of Proposed Rulemaking could be read to limit
communications between KMIGT, Trailblazer and their respective affiliates. In
addition, the Notice could be read to require separate staffing of KMIGT and its
affiliates, and Trailblazer and its affiliates. Comments on the Notice of
Proposed Rulemaking were due December 20, 2001. Numerous parties, including
KMIGT, have filed comment on the Proposed Standards of Conduct Rulemaking. On
May 21, 2002, FERC held a technical conference dealing with the Commission's
proposed changes in the Standard of Conduct Rulemaking. On June 28, 2002, KMIGT
and numerous other parties flied additional written comments under a procedure
adopted at the technical conference. The Proposed Rulemaking is awaiting further
Commission action. We believe that these matters, as finally adopted, will not
have a material adverse effect on our business, financial position or results of
operations.
Carbon Dioxide Litigation
Kinder Morgan CO2 Company, L.P. directly or indirectly through its
ownership interest in the Cortez Pipeline Company, along with other entities,
is a defendant in several actions in which the plaintiffs allege that the
defendants undervalued carbon dioxide produced from the McElmo Dome field and
overcharged for transportation costs, thereby allegedly underpaying royalties
and severance tax payments. The plaintiffs, who are seeking monetary damages
and injunctive relief, are comprised of royalty, overriding royalty and small
share working interest owners who claim that they were underpaid by the
defendants. These cases are: CO2 Claims Coalition, LLC v. Shell Oil Co., et
al., No. 96-Z-2451 (U.S.D.C. Colo. filed 8/22/96); Rutter & Wilbanks et al.
v. Shell Oil Co., et al., No. 00-Z-1854 (U.S.D.C. Colo. filed 9/22/00);
Watson v. Shell Oil Co., et al., No. 00-Z-1855 (U.S.D.C. Colo. filed
9/22/00); Ainsworth et al. v. Shell Oil Co., et al., No. 00-Z-1856 (U.S.D.C.
Colo. filed 9/22/00); United States ex rel. Crowley v. Shell Oil Company, et
al., No. 00-Z-1220 (U.S.D.C. Colo. filed 6/13/00); Shell Western E&P Inc. v.
Bailey, et al., No 98-28630 (215th Dist. Ct. Harris County, Tex. filed
6/17/98); Shores, et al. v. Mobil Oil Corporation, et al., No. GC-99-01184
(Texas Probate Court, Denton County filed 12/22/99); First State Bank of
Denton v. Mobil Oil Corporation, et al., No. PR-8552-01 (Texas Probate Court,
Denton County filed 3/29/01); and Celeste C. Grynberg v. Shell Oil Company,
et al., No. 98-CV-43 (Colo. Dist. Ct. Montezuma County filed 3/21/98).
17
At a hearing conducted in the United States District Court for the District
of Colorado on April 8, 2002, the Court orally announced that it had approved
the certification of proposed plaintiff classes and approved a proposed
settlement in the CO2 Claims Coalition, LLC, Rutter & Wilbanks, Watson,
Ainsworth and United States ex rel. Crowley cases. The Court entered a written
order approving the Settlement on May 6, 2002; plaintiffs counsel representing
Shores, et al appealed the court's decision to the 10th Circuit Court of
Appeals.
RSM Production Company et al. v. Kinder Morgan Energy Partners, L.P. et al.
Cause No. 4519, in the District Court, Zapata County Texas, 49th Judicial
District. On October 15, 2001, Kinder Morgan Energy Partners, L.P. was served
with the First Supplemental Petition filed by RSM Production Corporation on
behalf of the County of Zapata, State of Texas and Zapata County Independent
School District as plaintiffs. Kinder Morgan Energy Partners, L.P. was sued in
addition to 15 other defendants, including two other Kinder Morgan affiliates.
Certain entities we acquired in the Kinder Morgan Tejas acquisition are also
defendants in this matter. The Petition alleges that these taxing units relied
on the reported volume and analyzed heating content of natural gas produced from
the wells located within the appropriate taxing jurisdiction in order to
properly assess the value of mineral interests in place. The suit further
alleges that the defendants undermeasured the volume and heating content of that
natural gas produced from privately owned wells in Zapata County, Texas. The
Petition further alleges that the County and School District were deprived of ad
valorem tax revenues as a result of the alleged undermeasurement of the natural
gas by the defendants. On December 15, 2001, the defendants filed motions to
transfer venue on jurisdictional grounds. There are no further pretrial
proceedings at this time.
Quinque Operating Company, et al. v. Gas Pipelines, et al.
Will Price, et al. v. Gas Pipelines, et al., (f/k/a Quinque Operating
Company et al. v. Gas Pipelines, et al.), Stevens County, Kansas District Court,
Case No. 99 C 30. In May, 1999, three plaintiffs, Quinque Operating Company, Tom
Boles and Robert Ditto, filed a purported nationwide class action in the Stevens
County, Kansas District Court against some 250 natural gas pipelines and many of
their affiliates. The District Court is located in Hugoton, Kansas. Certain
entities we acquired in the Kinder Morgan Tejas acquisition are also defendants
in this matter. The Petition (recently amended) alleges a conspiracy to underpay
royalties, taxes and producer payments by the defendants' undermeasurement of
the volume and heating content of natural gas produced from nonfederal lands for
more than twenty-five years. The named plaintiffs purport to adequately
represent the interests of unnamed plaintiffs in this action who are comprised
of the nation's gas producers, State taxing agencies and royalty, working and
overriding owners. The plaintiffs seek compensatory damages, along with
statutory penalties, treble damages, interest, costs and fees from the
defendants, jointly and severally. This action was originally filed on May 28,
1999 in Kansas State Court in Stevens County, Kansas as a class action against
approximately 245 pipeline companies and their affiliates, including certain
Kinder Morgan entities. Subsequently, one of the defendants removed the action
to Kansas Federal District Court and the case was styled as Quinque Operating
Company, et al. v. Gas Pipelines, et al., Case No. 99-1390-CM, United States
District Court for the District of Kansas. Thereafter, we filed a motion with
the Judicial Panel for Multidistrict Litigation to consolidate this action for
pretrial purposes with the Grynberg False Claim Act cases referred to above,
because of common factual questions. On April 10, 2000, the MDL Panel ordered
that this case be consolidated with the Grynberg federal False Claims Act cases.
On January 12, 2001, the Federal District Court of Wyoming issued an oral ruling
remanding the case back to the State Court in Stevens County, Kansas. A case
management conference occurred in State Court in Stevens County, and a briefing
schedule was established for preliminary matters. Personal jurisdiction
discovery has commenced. Merits discovery has been stayed. Recently, the
defendants filed a motion to dismiss on grounds other than personal
jurisdiction, and a motion to dismiss of lack of personal jurisdiction for
non-resident defendants. The current Named plaintiffs are Will Price, Tom Boles,
Cooper Clark Foundation and Stixon Petroleum, Inc. Quinque Operating Company has
been dropped from the action as a Named Plaintiff.
Sweatman and Paz Gas Corporation v. Gulf Energy Marketin, LLC, et al.
Mel R. Sweatman and Paz Gas Corporation vs, Gulf Energy Marketing, LLC, et
al. On July 25, 2002, we were served with this suit for breach of contract,
tortious interference with existing contractual relationships, conspiracy to
commit tortuous interference and interference with prospective business
relationship. Mr. Sweatman and Paz Gas Corporation claim that, in connection
with our acquisition of Tejas Gas, LLC, we wrongfully caused gas volumes to be
shipped on our Kinder Morgan Texas Pipeline system instead of our Kinder Morgan
Tejas system. Mr. Sweatman and Paz Gas Corporation allege that this action
eliminated profit on Kinder Morgan Tejas, a portion of which Mr. Sweatman and
Paz Gas Corporation claim they are entitled under an agreement with a subsidiary
of ours acquired in the Tejas Gas acquisition. Our answer to this complaint has
not yet become due. Based on the information available to date and our
preliminary investigation, we believe this suit is without merit and intend to
defend it vigorously.
18
Although no assurances can be given, we believe that we have meritorious
defenses to all of 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 Act (CERCLA) generally imposes joint and several
liability for cleanup and enforcement costs on current or predecessor owners and
operators of a site, without regard to fault or the legality of the original
conduct. Our operations are also subject to federal, state and local laws and
regulations relating to protection of the environment. Although we believe our
operations are in substantial compliance with applicable environmental
regulations, risks of additional costs and liabilities are inherent in pipeline
and terminal operations, and there can be no assurance that we will not incur
significant costs and liabilities. Moreover, it is possible that other
developments, such as increasingly stringent environmental laws, regulations and
enforcement policies 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 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;
o several ground water hydrocarbon remediation efforts under administrative
orders issued by the California Regional Water Quality Control Board and
two other state agencies;
o groundwater and soil remediation efforts under administrative orders
issued by various regulatory agencies on those assets purchased from GATX
Corporation, comprising Kinder Morgan Liquids Terminals LLC, CALNEV Pipe
Line LLC and Central Florida Pipeline LLC; and
o a ground water remediation effort taking place between Chevron, Plantation
Pipe Line Company and the Alabama Department of Environmental Management.
In addition, we are from time to time involved in civil proceedings relating
to damages alleged to have occurred as a result of accidental leaks or spills of
refined petroleum products, natural gas liquids, natural gas and carbon dioxide.
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 nine sites. Additionally, review of assets related to
Kinder Morgan Texas Pipeline includes the environmental impacts from petroleum
releases to the soil and groundwater at six sites. Further delineation and
remediation of these impacts will be conducted. Reserves have been established
to address the closure of these issues.
On October 2, 2001, the jury rendered a verdict in the case of Walter
Chandler v. Plantation Pipe Line Company. The jury awarded the plaintiffs a
total of $43.8 million. The judge reduced the award to $42.6 million due to a
prior settlement with the plaintiffs by a third party. The verdict was divided
with the following award of damages:
o $0.3 million compensatory damages for property damage to the Evelyn
Chandler Trust;
o $4.1 million compensatory damages to Walter (Buster) Chandler;
o $1.2 million compensatory damages to Clay Chandler; and o $37 million
punitive damages.
Plantation has filed post judgment motions and an appeal of the verdict. The
appeal of this case will be directly heard by the Alabama Supreme Court. It is
anticipated that a decision by the Alabama Supreme Court will be received within
the next ten to fifteen months.
This case was filed in April 1997 by the landowner (Evelyn Chandler Trust)
and two residents of the property (Buster Chandler and his son, Clay Chandler).
The suit was filed against Chevron, Plantation and two individuals. The two
individuals were later dismissed from the suit. Chevron settled with the
plaintiffs in December 2000. The property and residences are directly across the
street from the location of a former Chevron products terminal. The Plantation
pipeline system traverses the Chevron terminal property. The suit alleges that
gasoline released from the terminal and pipeline contaminated the groundwater
under the plaintiffs' property. As noted above, a current
19
remediation effort is taking place between Chevron, Plantation and Alabama
Department of Environmental Management.
Although no assurance can be given, we believe that the ultimate resolution
of the environmental matters set forth in this note will not have a material
adverse effect on our business, financial position or results of operations. We
have recorded a total reserve for environmental claims in the amount of $67.8
million at June 30, 2002. As of June 30, 2002, we were not able to reasonably
estimate when the eventual settlements of these claims will occur.
Other
We are a defendant in various lawsuits arising from the day-to-day operations
of our businesses. Although no assurance can be given, we believe, based on our
experiences to date, that the ultimate resolution of such items will not have a
material adverse impact on our business, financial position or results of
operations. In addition, since many of our assets are subject to regulation, we
are subject to potential future challenges to our rates and to changes in
applicable rules and regulations that may have an adverse effect on our
business, financial position or results of operations.
4. Two-for-One Common Unit Split
On July 18, 2001, Kinder Morgan Management, LLC, the delegate of our general
partner, approved a two-for-one unit split of its outstanding shares and our
outstanding common units representing limited partner interests in us. The
common unit split entitled our common unitholders to one additional common unit
for each common unit held. Our partnership agreement provides that when a split
of our common units occurs, a unit split on our class B units and our i-units
will be effected to adjust proportionately the number of our class B units and
i-units. The two-for-one split occurred on August 31, 2001 to unitholders of
record on August 17, 2001. All references to the number of Kinder Morgan
Management, LLC shares, the number of our limited partner units and per unit
amounts in our consolidated financial statements and related notes, have been
restated to reflect the effect of the split for all periods presented.
5. Distributions
On May 15, 2002, we paid a cash distribution for the quarterly period ended
March 31, 2002, of $0.59 per unit to our common unitholders and to our class B
unitholders. Kinder Morgan Management, LLC, our sole i-unitholder, received
527,572 additional i-units based on the $0.59 cash distribution per common unit.
The distributions were declared on April 17, 2002, payable to unitholders of
record as of April 30, 2002.
On July 17, 2002, we declared a cash distribution for the quarterly period
ended June 30, 2002, of $0.61 per unit. The distribution will be paid on or
before August 14, 2002, to unitholders of record as of July 31, 2002. Our common
unitholders and class B unitholders will receive cash. Our sole i-unitholder
will receive a distribution in the form of additional i-units based on the $0.61
distribution per common unit. The number of i-units distributed will be 619,585.
For each outstanding i-unit that Kinder Morgan Management, LLC holds, a fraction
of an i-unit will be issued. The fraction is determined by dividing:
o the cash amount distributed per common unit
by
o the average of Kinder Morgan Management's shares' closing market prices
from July 15-26, 2002, the ten consecutive trading days preceding the date
on which the shares began to trade ex-dividend under the rules of the New
York Stock Exchange.
6. Intangibles
Effective January 1, 2002, we adopted Statement of Financial Accounting
Standards No. 141 "Business Combinations" and Statement of Financial Accounting
Standards No. 142 "Goodwill and Other Intangible Assets". These accounting
pronouncements require that we prospectively cease amortization of all
intangible assets having indefinite useful economic lives. Such assets,
including goodwill, are not to be amortized until their lives are determined to
be finite, however, a recognized intangible asset with an indefinite useful life
should be tested for impairment annually or on an interim basis if events or
circumstances indicate that the fair value of the asset has
20
decreased below its carrying value. We completed this initial transition
impairment test in June 2002 and determined that our goodwill is not impaired.
Our intangible assets include goodwill, lease value, contracts and
agreements. All of our intangible assets having definite lives are being
amortized on a straight-line basis over their estimated useful lives. SFAS Nos.
141 and 142 also require that we disclose the following information related to
our intangible assets still subject to amortization and our goodwill (in
thousands):
June 30, Dec. 31,
2002 2001
------------- ---------
Goodwill $ 655,632 $ 566,633
Accumulated amortization (19,899) (19,899)
------------ ------------
Goodwill, net 635,733 546,734
------------ ------------
Lease value 6,124 6,124
Contracts and other 10,712 10,739
Accumulated amortization (290) (200)
------------ ------------
Other intangibles, net 16,546 16,663
------------ ------------
Total intangibles, net $ 652,279 $ 563,397
============ ============
Changes in the carrying amount of goodwill for the six months ended June 30,
2002 are summarized as follows (in thousands):
Products Natural Gas CO2
Pipelines Pipelines Pipelines Terminals Total
--------- --------- --------- --------- -----
Balance at Dec. 31, 2001 $ 262,765 $ 87,452 $ 46,101 $ 150,416 $ 546,734
Goodwill acquired 417 -- -- -- 417
Goodwill dispositions, net -- -- -- -- --
Impairment losses -- -- -- -- --
----------- ---------- --------- --------- ----------
Balance at Mar. 31, 2002 $ 263,182 $ 87,452 $ 46,101 $ 150,416 $ 547,151
=========== ========== ========= ========= ==========
Goodwill acquired -- 83,262 -- 5,320 88,582
Goodwill dispositions, net -- -- -- -- --
Impairment losses -- -- -- -- --
----------- ---------- --------- --------- ----------
Balance at June 30, 2002 $ 263,182 $ 170,714 $ 46,101 $ 155,736 $ 635,733
=========== ========== ========= ========= ==========
Amortization expense consists of the following (in thousands):
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
-------- -------- -------- ----------
Goodwill $ -- $ 3,385 $ -- $ 5,967
Lease value 35 1,396 70 2,793
Contracts and other 10 10 20 20
-------- -------- -------- ----------
$ 45 $ 4,791 $ 90 $ 8,780
======== ======== ======== ==========
Our weighted average amortization period for our intangible assets is
approximately 42 years. The following table shows the estimated amortization
expense for these assets for each of the five succeeding fiscal years (in
thousands):
2003 $ 180
2004 $ 180
2005 $ 180
2006 $ 180
2007 $ 180
21
Had SFAS No. 142 been in effect prior to January 1, 2002, our reported
limited partners' interest in net income and net income per unit would have been
as follows (in thousands, except per unit amounts):
Three Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2002 2001 2002 2001
---- ---- ---- ----
Reported limited partners' interest in net income $ 79,283 $ 53,620 $ 158,922 $ 113,665
Add: limited partners' interest in goodwill amortization -- 3,350 -- 5,907
-------- -------- --------- ---------
Adjusted limited partners' interest in net income $ 79,283 $ 56,970 $ 158,922 $ 119,572
======== ======== ========= =========
Basic limited partners' net income per unit:
Reported net income $ 0.48 $ 0.36 $ 0.96 $ 0.80
Goodwill amortization -- 0.02 -- 0.04
-------- -------- --------- ---------
Adjusted net income $ 0.48 $ 0.38 $ 0.96 $ 0.84
======== ======== ========= =========
Diluted limited partners' net income per unit:
Reported net income $ 0.48 $ 0.36 $ 0.95 $ 0.80
Goodwill amortization -- 0.02 -- 0.04
-------- -------- --------- ---------
Adjusted net income $ 0.48 $ 0.38 $ 0.95 $ 0.84
======== ======== ========= =========
7. Debt
Our debt and credit facilities as of June 30, 2002, consist primarily of:
o a $750 million unsecured 364-day credit facility due October 23, 2002;
o a $200 million unsecured 364-day credit facility due February 20, 2003;
o an $85.2 million unsecured two-year credit facility due June 29, 2003
(Trailblazer Pipeline Company is the obligor on the facility);
o a $300 million unsecured five-year credit facility due September 29,
2004;
o $79.5 million of Series F First Mortgage Notes due December 2004 (our
subsidiary, SFPP, L.P. is the obligor on the notes);
o $200 million of 8.00% Senior Notes due March 15, 2005;
o $40 million of Plaquemines, Louisiana Port, Harbor, and Terminal
District Revenue Bonds due March 15, 2006 (our subsidiary, International
Marine Terminals, is the obligor on the bonds);
o $35 million of 7.84% Senior Notes, with a final maturity of July 2008 (our
subsidiary, Central Florida Pipe Line LLC, is the obligor on the notes);
o $250 million of 6.30% Senior Notes due February 1, 2009;
o $250 million of 7.50% Senior Notes due November 1, 2010;
o $700 million of 6.75% Senior Notes due March 15, 2011;
o $450 million of 7.125% Senior Notes due March 15, 2012;
o $25 million of New Jersey Economic Development Revenue Refunding Bonds
due January 15, 2018 (our subsidiary, Kinder Morgan Liquids Terminals
LLC, is the obligor on the bonds);
o $87.9 million of Industrial Revenue Bonds with final maturities ranging
from September 2019 to December 2024 (our subsidiary, Kinder Morgan
Liquids Terminals LLC, is the obligor on the bonds);
o $23.7 million of tax-exempt bonds due 2024 (our subsidiary, Kinder
Morgan Operating L.P. "B", is the obligor on the bonds);
o $300 million of 7.40% Senior Notes due March 15, 2031;
o $300 million of 7.75% Senior Notes due March 15, 2032; and
o a $1.25 billion short-term commercial paper program.
None of our debt or credit facilities are subject to payment acceleration as
a result of any change to our credit ratings.
Our short-term debt at June 30, 2002, consisted of:
o $996.8 million of commercial paper borrowings;
o $42.5 million under the SFPP, L.P. 10.7% First Mortgage Notes;
o $31.0 million under Trailblazer's unsecured two-year credit facility;
22
o $5.0 million under the Central Florida Pipeline LLC Notes; and
o $3.5 million in other borrowings.
On August 6, 2002, Kinder Morgan Management, LLC issued in a public offering,
an additional 12,478,900 of its shares, including 478,900 shares upon exercise
by the underwriters of an over-allotment option, at a price of $27.50 per share,
less commissions and underwriting expenses. The net proceeds from the offering
were used to buy i-units from us. After commissions, underwriting expenses and
unit issuance costs, we will receive net proceeds of approximately $328.6
million for the issuance of 12,478,900 i-units. We used the proceeds from the
i-unit issuance to reduce the borrowings under our commercial paper program.
We intend and have the ability to refinance $276.3 million of our short-term
debt on a long-term basis under our unsecured five-year credit facility. We do
not anticipate any liquidity problems. Our average interest rate for outstanding
borrowings during the second quarter of 2002 was approximately 5.06% per annum.
For additional information regarding our debt facilities, see Note 9 to our
consolidated financial statements included in our Form 10-K for the year ended
December 31, 2001.
Credit Facilities
No borrowings were outstanding under our three credit facilities at June 30,
2002. However, the amount available for borrowing under our credit facilities is
reduced by a $23.7 million letter of credit that supports Kinder Morgan
Operating L.P. "B"'s tax-exempt bonds and our outstanding commercial paper
borrowings.
Our three credit facilities are with a syndicate of financial institutions.
First Union National Bank is the administrative agent under our five-year credit
facility and our 364-day facility that expires on October 23, 2002. JPMorgan
Chase Bank is the administrative agent under our 364-day facility that expires
on February 20, 2003. Interest on these three credit facilities accrues at our
option at a floating rate equal to either:
o the applicable administrative agent's base rate (but not less than the
Federal Funds Rate, plus 0.5%); or
o LIBOR, plus a margin, which varies depending upon the credit rating of our
long-term senior unsecured debt.
Our 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, 2002, our unamortized liability balance due on the various series
of our senior notes was as follows (in millions):
8.0% senior notes due March 15, 2005 $ 199.8
6.30% senior notes due February 1, 2009 249.4
7.5% senior notes due November 1, 2010 248.7
6.75% senior notes due March 15, 2011 698.2
7.125% senior notes due March 15, 2012 448.0
7.40% senior notes due March 15, 2031 299.3
7.75% senior notes due March 15, 2032 298.5
-----
Total $2,441.9
========
Commercial Paper Program
Effective March 31, 2002 and June 30, 2002, our commercial paper program
provided for the issuance of up to $1.25 billion of commercial paper. Borrowings
under our commercial paper program reduce the borrowings allowed under our
credit facilities. As of June 30, 2002, we had $996.8 million of commercial
paper outstanding with an interest rate of 2.14%.
Trailblazer Pipeline Company Debt
At June 30, 2002, the outstanding balance under Trailblazer's $85.2 million
two-year revolving credit facility was $31.0 million. The revolving credit
facility expires on June 29, 2003, and had a weighted average interest rate of
2.805% at June 30, 2002, which reflects LIBOR plus a margin of 0.875%. Pursuant
to the terms of the revolving
23
credit facility, Trailblazer partnership distributions are restricted by certain
financial covenants. In late July, we paid the outstanding balance under
Trailblazer's revolving credit facility.
Kinder Morgan Operating L.P. "B" Debt
The $23.7 million principal amount of tax-exempt bonds due 2024 were issued
by the Jackson-Union Counties Regional Port District. These bonds bear interest
at a weekly floating market rate. During the second quarter of 2002, the
weighted-average interest rate on these bonds was 1.45% per annum, and at June
30, 2002, the interest rate was 1.33%. We have an outstanding letter of credit
issued under our credit facilities that supports our tax-exempt bonds. The
letter of credit reduces the amount available for borrowing under our credit
facilities.
International Marine Terminals Debt
As of February 1, 2002, we own a 66 2/3% interest in International Marine
Terminals (IMT) partnership (see Note 2). The principal assets owned by IMT are
dock and wharf facilities financed by the Plaquemines Port, Harbor and Terminal
District (Louisiana) $40,000,000 Adjustable Rate Annual Tender Port Facilities
Revenue Refunding Bonds (International Marine Terminals Project) Series 1984A
and 1984B. The bonds mature on March 15, 2006. The bonds are backed by two
letters of credit issued by KBC Bank N.V. On March 19, 2002, an Amended and
Restated Letter of Credit Reimbursement Agreement relating to the letters of
credit was entered into by IMT and KBC Bank. In connection with that agreement,
we agreed to guarantee the obligations of IMT in proportion to our ownership
interest. Our obligation is approximately $30.3 million for principal, plus
interest and other fees.
Cortez Pipeline Company Debt
Pursuant to a certain Throughput and Deficiency Agreement, the owners of
Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% owner; a
subsidiary of Exxon Mobil Corporation - 37% owner; and Cortez Vickers Pipeline
Company - 13% owner) are required, on a percentage ownership basis, to
contribute capital to Cortez Pipeline Company in the event of a cash deficiency.
The Throughput and Deficiency Agreement contractually supports the financings of
Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline
Company, by obligating the owners of Cortez Pipeline Company to fund cash
deficiencies at Cortez Pipeline Company, including cash deficiencies relating to
the repayment of principal and interest. Parent companies of the respective
Cortez Pipeline Company owners further severally guarantee, on a percentage
basis, the obligations of the Cortez Pipeline Company owners under the
Throughput and Deficiency Agreement.
Due to our indirect ownership of Cortez 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, 2002, the debt facilities of Cortez Capital Corporation consisted
of:
o a $127 million committed 364-day revolving credit facility due December
26, 2002;
o a $48 million committed 364-day revolving credit facility due July 17,
2002;
o $115.7 million of Series D notes due May 15, 2013; and
o a $175 million short-term commercial paper program.
At June 30, 2002, Cortez had $155.8 million of commercial paper outstanding
with an interest rate of 1.82%, the average interest rate on the series D notes
was 6.9322% and there were no borrowings under the credit facilities.
On July 16, 2002, the $127 million and the $48 million revolving credit
facilities were combined into one $175 million committed revolving credit
facility due December 26, 2002.
8. Partners' Capital
At June 30, 2002, our partners' capital consisted of 129,922,218 common
units, 5,313,400 class B units and 31,617,905 i-units. Together, these
166,853,523 units represent the limited partners' interest and an effective 98%
economic interest in the Partnership, exclusive of our general partner's
incentive distribution. Our common unit total consisted of 111,020,191 units
held by third parties, 17,178,027 units held by KMI and its consolidated
affiliates (excluding our general partner) and 1,724,000 units held by our
general partner. Our class B units were held entirely by Kinder Morgan, Inc. and
our i-units were held entirely by Kinder Morgan Management, LLC. Our general
partner has an effective 2% interest in the Partnership, excluding the general
partner's incentive distribution.
24
At December 31, 2001, our Partners' capital consisted of 129,855,018 common
units, 5,313,400 class B units and 30,636,363 i-units. Our total common units
outstanding consisted of 110,071,392 units held by third parties, 18,059,626
units held by Kinder Morgan, Inc. and its consolidated affiliates (excluding our
general partner) and 1,724,000 units held by our general partner. Our class B
units were held entirely by Kinder Morgan, Inc. and our i-units were held
entirely by Kinder Morgan Management, LLC.
Our class B units were issued in December 2000. The class B units are similar
to our common units except that they are not eligible for trading on the New
York Stock Exchange. Our i-units were initially issued in May 2001. The i-units
are a separate class of limited partner interests in us. All of our i-units are
owned by Kinder Morgan Management, LLC, a wholly-owned subsidiary of our general
partner, and are not publicly traded. In accordance with its limited liability
company agreement, Kinder Morgan Management's activities are restricted to being
a limited partner in, and controlling and managing the business and affairs of,
the Partnership, our operating partnerships and our subsidiaries.
Through the combined effect of the provisions in our partnership agreement
and the provisions of Kinder Morgan Management, LLC's limited liability company
agreement, the number of outstanding Kinder Morgan Management, LLC shares and
the number of i-units will at all times be equal. Furthermore, under the terms
of our partnership agreement, we agreed that we will not, except in liquidation,
make a distribution on an i-unit other than in additional i-units or a security
that has in all material respects the same rights and privileges as our i-units.
The number of i-units we distribute to Kinder Morgan Management, LLC is based
upon the amount of cash we distribute to the owners of our common units.
Typically, if cash is paid to the holders of our common units, we will issue
additional i-units to Kinder Morgan Management, LLC. The fraction of an i-unit
paid per i-unit owned by Kinder Morgan Management, LLC will have the same value
as the cash payment on the common unit. Based on the preceding, Kinder Morgan
Management, LLC received 527,572 i-units on May 15, 2002. These additional
i-units distributed were based on the $0.59 per unit distributed to our common
unitholders on that date.
For the purposes of maintaining partner capital accounts, our partnership
agreement specifies that items of income and loss shall be allocated among the
partners in accordance with their percentage interests. Normal allocations
according to percentage interests are made, however, only after giving effect to
any priority income allocations in an amount equal to the incentive
distributions that are allocated 100% to our general partner.
Incentive distributions allocated to our general partner are determined by
the amount that quarterly distributions to unitholders exceed certain specified
target levels. Our distribution of $0.59 per unit paid on May 15, 2002 for the
first quarter of 2002 required an incentive distribution to our general partner
of $61.0 million. Our distribution of $0.525 per unit paid on May15, 2001 for
the first quarter of 2001 required an incentive distribution to our general
partner of $41.0 million. The increased incentive distribution to our general
partner paid for the first quarter of 2002 over the distribution paid for the
first quarter of 2001 reflects the increase in the amount distributed per unit
as well as the issuance of additional units.
Our declared distribution for the second quarter of 2002 of $0.61 per unit
will result in an incentive distribution to our general partner of $64.4
million. This compares to our distribution of $0.525 per unit and incentive
distribution to our general partner of $50.1 million for the second quarter of
2001.
Subsequent Event
On August 6, 2002, Kinder Morgan Management, LLC issued in a public offering,
an additional 12,478,900 of its shares, including 478,900 shares upon exercise
by the underwriters of an over-allotment option, at a price of $27.50 per share,
less commissions and underwriting expenses. The net proceeds from the offering
were used to buy i-units from us. After commissions, underwriting expenses and
unit issuance costs, we will receive net proceeds of approximately $328.6
million for the issuance of 12,478,900 i-units. We used the proceeds from the
i-unit issuance to reduce the debt we incurred in our acquisition of Kinder
Morgan Tejas during the first quarter of 2002.
9. Comprehensive Income
Statement of Financial Accounting Standards No. 130, "Accounting for
Comprehensive Income", requires that enterprises report a total for
comprehensive income. For each of the six months ended June 30, 2002 and 2001,
the only difference between our net income and our comprehensive income was the
unrealized gain or loss on derivatives utilized for hedging purposes. For more
information on our hedging activities, see Note 10. Our total comprehensive
income is as follows (in thousands):
25
Three Months Ended Six Months Ended
June 30, June 30,
2002 2001 2002 2001
---------- ------------ --------- ---------
Net income $144,517 $104,226 $285,950 $205,893
Cumulative effect transition adjustment -- -- -- (22,797)
Change in fair value of derivatives used for hedging purposes (14,920) (16,798) (81,856) (37,007)
Reclassification of change in fair value of derivatives to net income 11,531 13,716 (12,828) 53,974
-------- --------- -------- ------
Comprehensive income $141,128 $101,144 $191,266 $200,063
======== ======== ========= ========
10. Risk Management
Hedging Activities
Effective January 1, 2001, we adopted Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" as amended by Statement of Financial Accounting Standards No. 137,
"Accounting for Derivative Instruments and Hedging Activities - Deferral of the
Effective Date of FASB Statement No.133" and No. 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities". SFAS No. 133 established
accounting and reporting standards requiring that every derivative financial
instrument (including certain derivative instruments embedded in other
contracts) be recorded in the balance sheet as either an asset or liability
measured at its fair value. SFAS No. 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. If the derivatives meet those criteria, SFAS
No. 133 allows a derivative's gains and losses to offset related results on the
hedged item in the income statement, and requires that a company formally
designate a derivative as a hedge and document and assess the effectiveness of
derivatives associated with transactions that receive hedge accounting.
Our normal business activities expose us to risks associated with changes in
the market price of natural gas and associated transportation, natural gas
liquids, crude oil and carbon dioxide. Through Kinder Morgan, Inc., we use
energy financial instruments to reduce our risk of price changes in the spot and
fixed price of natural gas, natural gas liquids and crude oil markets. Our risk
management activities are only used in order to protect our profit margins and
our risk management policies prohibit us from engaging in speculative trading.
Commodity-related activities of our risk management group are monitored by our
Risk Management Committee, which is charged with the review and enforcement of
our management's risk management policy.
The fair value of these risk management instruments reflects the estimated
amounts that we would receive or pay to terminate the contracts at the reporting
date, thereby taking into account the current unrealized gains or losses on open
contracts. We have available market quotes for substantially all of the
financial instruments that we use. Our Form 10-K for the year ended December 31,
2001 contains additional information about the risks we face and the hedging
program we employ to mitigate those risks.
Approximately $0.3 million was recognized in earnings as a loss during the
second quarter of 2002 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. For the second quarter of 2001,
approximately $0.1 million was recognized in earnings as a gain as a result of
ineffectiveness of these hedges. Approximately $0.5 million was recognized in
earnings as a gain during the first six months of 2002 as a result of
ineffectiveness of these hedges, and for the first six months of 2001,
approximately $0.2 million was recognized in earnings as a loss as a result of
ineffectiveness of these hedges. For each of the six months ended June 30, 2002
and 2001, there was no component of the derivative instruments' gain or loss
excluded from the assessment of hedge effectiveness.
The gains and losses included in Accumulated other comprehensive income will
be reclassified into earnings as the hedged sales and purchases take place.
Approximately $23.3 million of the Accumulated other comprehensive income
balance of $30.9 million representing unrecognized net losses on derivative
activities at June 30, 2002 is expected to be reclassified into earnings during
the next twelve months. During the six months ended June 30, 2002, no gains or
losses were reclassified into earnings as a result of the discontinuance of cash
flow hedges due to a determination that the forecasted transactions will no
longer occur by the end of the originally specified time period.
The differences between the current market value and the original physical
contracts value associated with hedging activities are primarily reflected as
other current assets and accrued other current liabilities in the accompanying
consolidated balance sheets. At June 30, 2002, our balance of $71.6 million of
other current assets included approximately $44.2 million related to risk
management hedging activities, and our balance of $218.2
26
million of accrued other current liabilities included approximately $68.0
million related to risk management hedging activities. At December 31, 2001, our
balance of $194.9 million of other current assets included approximately $163.7
million related to risk management hedging activities, and our balance of $209.9
million of accrued other current liabilities included approximately $117.8
million related to risk management hedging activities.
At June 30, 2002, our balance of $115.6 million of Deferred charges and other
assets included approximately $11.6 million related to risk management hedging
activities, and our balance of $234.2 million of Other deferred credits included
approximately $19.4 million related to risk management hedging activities. At
December 31, 2001, our balance of $75.0 million of Deferred charges and other
assets included approximately $22.0 million related to risk management hedging
activities, and our balance of $246.5 million of Other deferred credits included
approximately $4.7 million related to risk management hedging activities.
While we enter into derivative transactions only with investment grade
counterparties and actively monitor their credit ratings, it is nevertheless
possible that from time to time losses will result from counterparty credit
risk.
Interest Rate Swaps
In order to maintain a cost effective capital structure, it is our policy to
borrow funds using a mix of fixed rate debt and variable rate debt. As of June
30, 2002, we have entered into interest rate swap agreements with a notional
principal amount of $1.35 billion for the purpose of hedging the interest rate
risk associated with our fixed and floating rate debt obligations.
A notional principal amount of $1.15 billion of these agreements effectively
converts the interest expense associated with the following series of our senior
notes from fixed rates to variable rates based on an interest rate of LIBOR plus
a spread:
o 8.0% senior notes due March 15, 2005;
o 6.30% senior notes due February 1, 2009;
o 7.125% senior notes due March 15, 2012;
o 7.40% senior notes due March 15, 2031; and
o 7.75% senior notes due March 15, 2032.
The swap agreements for our senior notes have termination dates that
correspond to the maturity dates of such series. The swap agreements for our
7.40% senior notes contain mutual cash-out provisions at the then-current
economic value every seven years. The swap agreements for our 7.125% senior
notes contain cash-out provisions at the then-current economic value at March
15, 2009. The swap agreements for our 7.75% senior notes contain mutual cash-out
provisions at the then-current economic value every five years. As of December
31, 2001, we were party to interest rate swap agreements with a total notional
principal amount of $900 million.
We also maintain swap agreements that effectively convert the interest
expense associated with $200 million of our floating rate debt to fixed rate.
The maturity dates of these swap agreements range from November 3, 2002 to
August 1, 2005.
These swaps have been designated as fair value hedges as defined by SFAS No.
133. These swaps also meet the conditions required to assume no ineffectiveness
under SFAS No. 133 and, therefore, we have accounted for them using the
"shortcut" method prescribed for fair value hedges by SFAS No. 133. Accordingly,
we will adjust the carrying value of each swap to its fair value each quarter,
with an offsetting entry to adjust the carrying value of the debt securities
whose fair value is being hedged. We will record interest expense equal to the
variable rate payments, which will be accrued monthly and paid semi-annually. At
June 30, 2002, we recognized an asset of $33.7 million for the net fair value of
our swap agreements and we included this amount with Deferred charges and other
assets on the accompanying balance sheet. At December 31, 2001, we recognized a
liability of $5.4 million for the net fair value of our swap agreements and we
included this amount with Other Long-Term Liabilities and Deferred Credits on
the accompanying balance sheet. We are exposed to credit related losses in the
event of nonperformance by counterparties to these interest rate swap
agreements, but, given their existing credit ratings, we do not expect any
counterparties to fail to met their obligations.
11. Reportable Segments
We divide our operations into four reportable business segments:
27
o Products Pipelines;
o Natural Gas Pipelines;
o CO2 Pipelines; and
o Terminals.
We evaluate performance based on each segment's earnings, which exclude
general and administrative expenses, third-party debt costs, interest income and
expense and minority interest. Our reportable segments are strategic business
units that offer different products and services. Each segment is managed
separately because each segment involves different products and marketing
strategies.
Our Products Pipelines segment derives its revenues primarily from the
transportation of refined petroleum products, including gasoline, diesel fuel,
jet fuel and natural gas liquids. Our Natural Gas Pipelines segment derives its
revenues primarily from the gathering 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 and from the production of crude oil from fields in
the Permian Basin of West Texas. Our Terminals segment derives its revenues
primarily from the transloading and storing of refined petroleum products and
dry and liquid bulk products, including coal, petroleum coke, cement, alumina,
salt, and chemicals.
Financial information by segment follows (in thousands):
Three Months Ended June 30, Six Months Ended June 30,
2002 2001 2002 2001
------------ ------------- ------------ ----------
Revenues
Products Pipelines $ 145,641 $ 137,181 $ 280,459 $ 327,874
Natural Gas Pipelines 800,946 479,224 1,338,503 1,205,509
CO2 Pipelines 34,416 32,143 66,540 61,245
Terminals 109,933 87,207 208,499 169,772
------------ ----------- ------------- ----------
Total consolidated revenues $ 1,090,936 $ 735,755 $ 1,894,001 $1,764,400
============ =========== ============= ==========
Operating income
Products Pipelines $ 88,067 $ 81,445 $ 166,640 $ 149,259
Natural Gas Pipelines 55,399 26,829 116,906 80,238
CO2 Pipelines 13,852 16,531 26,486 31,035
Terminals 45,239 34,782 87,913 68,050
------------ ----------- ------------- -----------
Total segment operating income 202,557 159,587 397,945 328,582
Corporate administrative expenses (30,210) (20,991) (59,742) (51,635)
------------- ------------ -------------- -----------
Total consolidated operating income $ 172,347 $ 138,596 $ 338,203 $ 276,947
============= ============ ============== ===========
Earnings from equity investments, net of amortization of excess costs
Products Pipelines $ 8,286 $ 6,266 $ 15,466 $ 11,181
Natural Gas Pipelines 5,903 5,174 11,959 10,450
CO2 Pipelines 8,761 7,454 17,402 16,213
Terminals (47) -- (47) --
------------- ------------ -------------- ----------
Consolidated equity earnings, net of amortization $ 22,903 $ 18,894 $ 44,780 $ 37,844
============= ============ =============== ==========
Income taxes and Other, net - income (expense)
Products Pipelines $ (2,980) $ (2,546) $ (5,755) $ (4,648)
Natural Gas Pipelines 14 (7) 19 3
CO2 Pipelines (4) (158) 90 93
Terminals (1,678) (2,645) (3,453) (3,629)
------------- ------------ ------------- ----------
Total consolidated income taxes and Other, net $ (4,648) $ (5,356) $ (9,099) $ (8,181)
============= ============ ============= ===========
Segment earnings
Products Pipelines $ 93,373 $ 85,165 $ 176,351 $ 155,792
Natural Gas Pipelines 61,316 31,996 128,884 90,691
CO2 Pipelines 22,609 23,827 43,978 47,341
Terminals 43,514 32,137 84,413 64,421
------------- ----------- ------------ ------------
Total segment earnings 220,812 173,125 433,626 358,245
Interest and corporate administrative expenses (a) (76,295) (68,899) (147,676) (152,352)
------------- ------------ ------------- ------------
Total consolidated net income $ 144,517 $ 104,226 $ 285,950 $ 205,893
============= =============== ============= ============
(a) Includes interest and debt expense, general and
administrative expenses, minority interest expense, and other insignificant
items.
28
June 30, Dec. 31,
2002 2001
------------------- -------------------
Assets
Products Pipelines $ 3,137,387 $ 3,095,899
Natural Gas Pipelines 2,999,386 2,058,836
CO2 Pipelines 522,456 503,565
Terminals 1,069,146 990,760
------------------- -------------------
Total segment assets 7,728,375 6,649,060
Corporate assets (a) 177,572 83,606
------------------- -------------------
Total consolidated assets $ 7,905,947 $ 6,732,666
=================== ===================
(a) Includes cash, cash equivalents and certain unallocable deferred charges
12. New Accounting Pronouncements
Statement of Financial Accounting Standards No. 141 "Business Combinations"
supersedes 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
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. This Statement requires disclosure of the primary
reasons for a business combination and the allocation of the purchase price paid
to the assets acquired and liabilities assumed by major balance sheet caption.
We adopted SFAS No. 141 on January 1, 2002. Refer to Note 2 for more detail
about our acquisitions.
Statement of Financial Accounting Standards No. 142 "Goodwill and Other
Intangible Assets" supersedes 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. We made our initial assessment in June 2002. After this initial
assessment, we will test our goodwill for impairment annually.
SFAS No. 142 applies to any goodwill acquired in a business combination
completed after June 30, 2001. 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". An intangible asset with an indefinite
useful life can no longer be amortized until its useful life becomes
determinable. This Statement requires disclosure of information about goodwill
and other intangible assets in the years subsequent to their acquisition that
was not previously required. Required disclosures include information about the
changes in the carrying amount of goodwill from period to period and the
carrying amount of intangible assets by major intangible asset class.
After June 30, 2001, we completed five acquisitions which resulted in the
recognition of goodwill. These acquisitions are as follows:
o The Boswell Oil Company (acquired assets);
o Stolt-Nielsen (acquired assets of two subsidiaries);
o Kinder Morgan Tejas;
o Trailblazer Pipeline Company (the remaining 33 1/3% ownership interest);
and
o Milwaukee Bagging Operations.
Following our adoption of SFAS No. 142 on January 1, 2002, goodwill of
approximately $635.7 million at June 30, 2002 is no longer subject to
amortization over its estimated useful life.
Statement of Financial Accounting Standards No. 143, "Accounting for Asset
Retirement Obligations", issued in July 2001 by the Financial Accounting
Standards Board, requires companies to record a liability relating to the
retirement and removal of assets used in their business. The liability is
initially recorded at its fair value, and the relative asset value is increased
by the same amount. Over the life of the asset, the liability will be accreted
to its future value and eventually extinguished when the asset is taken out of
service. The provisions of this statement are effective for fiscal years
beginning after June 15, 2002. We have not yet quantified the impacts of
adopting this Statement on our financial position or results of operations.
29
Statement of Financial Accounting Standards No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" retains the requirements of SFAS
121, mentioned above; however, this statement requires that long-lived assets
that are to be disposed of by sale be measured at the lower of book value or
fair value less the cost to sell it. Furthermore, the scope of discontinued
operations is expanded to include all components of an entity with operations of
the entity in a disposal transaction. We adopted SFAS No. 144 on January 1, 2002
and the adoption has not had a material impact on our business, financial
position or results of operations.
In April 2002, the Financial Accounting Standards Board issued SFAS No. 145,
"Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement
No. 13, and Technical Corrections." This Statement eliminates the current
requirement that gains and losses on debt extinguishment must be classified as
extraordinary items in the income statement. Instead, such gains and losses will
be classified as extraordinary items only if they are deemed to be unusual and
infrequent, in accordance with the current GAAP criteria for extraordinary
classification. In addition, SFAS No. 145 eliminates an inconsistency in lease
accounting by requiring that modifications of capital leases that result in
reclassification as operating leases be accounted for consistent with
sale-leaseback accounting rules. This Statement also contains other
nonsubstantive corrections to authoritative accounting literature. The changes
related to debt extinguishment will be effective for fiscal years beginning
after May 15, 2002, and the changes related to lease accounting will be
effective for transactions occurring after May 15, 2002. Adoption of this
statement will not have any immediate effect on our consolidated financial
statements. We will apply this guidance prospectively.
In June 2002, the Financial Accounting Standards Board issued SFAS No. 146,
"Accounting for Costs Associated with Exit or Disposal Activities," which
addresses accounting for restructuring and similar costs. SFAS No. 146
supersedes previous accounting guidance, principally Emerging Issues Task
Force Issue No. 94-3. We will adopt the provisions of SFAS No. 146 for
restructuring activities initiated after December 31, 2002. SFAS No. 146
requires that the liability for costs associated with an exit or disposal
activity be recognized when the liability is incurred. Under EITF No. 94-3,
a liability for an exit cost was recognized at the date of the company's
commitment to an exit plan. SFAS No. 146 also establishes that the liability
should initially be measured and recorded at fair value. Accordingly, SFAS
No. 146 may affect the timing of recognizing future restructuring costs as
well as the amounts recognized.
30
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
Results of Operations
Second Quarter 2002 Compared With Second Quarter 2001
Despite the current economic uncertainty, our second quarter results
reflected the continued growth in earnings that has occurred since the fourth
quarter of 2000. For the seventh consecutive quarter, we reported record
earnings.
Total consolidated net income for the quarter was a record $144.5 million
($0.48 per diluted unit), a 39% increase from the $104.2 million ($0.36 per
diluted unit) in net income reported for the second quarter of 2001. Revenues
for the second quarter of 2002 totaled $1,091 million, compared with $735.8
million in the same year-earlier period. Second quarter 2002 operating income
was $172.3 million versus $138.6 million in the second quarter of 2001.
Operating expenses, consisting of our combined cost of sales, fuel, power and
operating and maintenance expenses, were $832.1 million in the second quarter of
2002, compared with $527.7 million in the same period a year ago.
The quarter-to-quarter increases in our earnings, revenues and expenses were
driven by volume growth from most of our assets and by the acquisitions of
pipeline and terminal businesses that we made since the end of the second
quarter of 2001. The largest of these acquisitions was the January 31, 2002
purchase of Kinder Morgan Tejas. Kinder Morgan Tejas' operations include a
3,400-mile intrastate natural gas pipeline system that has good access to
natural gas supply basins and provides a strategic, complementary fit with our
other natural gas pipeline assets in Texas, particularly Kinder Morgan Texas
Pipeline.
Second quarter earnings from equity investments, net of amortization of
excess costs, increased 21% from the same period last year, primarily from
higher returns on our investment in Plantation Pipe Line Company. Total equity
earnings, net of amortization of excess costs were $22.9 million in the second
quarter of 2002 versus $18.9 million in the second quarter of 2001. In addition,
on July 17, 2002, we declared a record cash distribution of $0.61 per unit for
the second quarter of 2002 (an annualized rate of $2.44). Our second quarter
2002 distribution is up 16% from the $0.525 per unit distribution made for the
second quarter of 2001. In addition, beginning in April 2002, our general and
administrative expenses include our entire payroll tax expense and all prior
periods have been restated to reflect the effect of this reclassification.
Products Pipelines
Our Products Pipelines segment reported earnings of $93.4 million on revenues
of $145.6 million in the second quarter of 2002. In the second quarter of 2001,
the segment reported earnings of $85.2 million on revenues of $137.2 million.
The quarter-to-quarter increases of 10% in earnings and 6% in revenues were
driven by improved performance from existing assets and by higher returns from
our 44.8% ownership interest in the Cochin Pipeline System. Effective December
31, 2001, we purchased an additional 10% ownership interest in Cochin and as a
result, we realized a $1.4 million increase in second quarter earnings as
compared to last year. Revenues from Cochin also increased due to higher volumes
and tariffs. Revenues from our Pacific operations increased $1.4 million (2%)
primarily as a result of slightly higher (2%) average tariff rates and the
delivery of higher gasoline volumes.
Combined operating expenses for our Products Pipelines segment were $36.7
million in the second quarter of 2002 versus $34.4 million in the second quarter
of 2001. The $2.3 million increase (7%) was primarily due to higher fuel and
power expenses on our Pacific operations' pipelines and higher expenses
associated with our increased investment in Cochin.
Earnings from our Products Pipelines' equity investments, net of amortization
of excess costs, were $8.3 million in the second quarter of 2002 versus $6.3
million in the same quarter of 2001. The $2.0 million increase was mainly
related to higher equity earnings from our 51% ownership interest in Plantation
Pipe Line Company. Plantation reported all-time record throughput in the second
quarter of 2002, transporting 663,000 barrels per day of refined petroleum
products throughout the southeastern United States.
Natural Gas Pipelines
Our Natural Gas Pipelines segment reported earnings of $61.3 million on
revenues of $800.9 million in the second quarter of 2002. In the second quarter
of 2001, the segment reported earnings of $32.0 million on revenues of $479.2
million. The $29.3 million increase in segment earnings included $21.1 million
resulting from the
31
inclusion of Kinder Morgan Tejas. The remaining increase was the result of
improved earnings associated with both the pipeline expansion at Trailblazer
Pipeline Company and the elimination of lease payments at Kinder Morgan Texas
Pipeline. The $321.7 million increase in overall segment revenues resulted
primarily from the inclusion of revenues earned by recently acquired Kinder
Morgan Tejas. For the second quarter of 2002, Kinder Morgan Tejas reported
revenues of $430.4 million. Additionally, Trailblazer Pipeline Company reported
a $5.8 million increase (82%) in quarter-to-quarter revenues, mainly the result
of increased contract demand volume on the recently expanded pipeline.
Offsetting the overall increase in segment revenues was a $103.4 million
decrease in revenues earned by our Kinder Morgan Texas Pipeline system, and an
$8.5 million decrease in revenues earned by our Casper and Douglas natural gas
gathering and processing systems. Both of these decreases were primarily related
to a decline in gas prices since the second quarter of 2001.
The segment's operating expenses totaled $728.6 million in the second quarter
of 2002 and $442.5 million in the second quarter of 2001. The $286.1 million
increase in segment operating expenses includes $404.3 million in expenses from
Kinder Morgan Tejas. Excluding the results of Kinder Morgan Tejas, the segment's
operating expenses declined $118.2 million in the second quarter of 2002,
primarily the result of the drop in natural gas prices. Kinder Morgan Texas
Pipeline reported a $109.0 million decrease in operating expenses, mostly
consisting of lower gas purchase costs and the elimination of lease operating
expenses. Casper and Douglas reported a $7.7 million decrease in operating
expenses, mostly due to the lower gas prices' effects on its gas gathering and
processing operations.
Earnings from equity investments, net of amortization of excess costs, were
essentially flat for the quarter. The segment reported $5.9 million in net
equity earnings for the second quarter of 2002 versus $5.2 million for the same
prior year period. The slight $0.7 million increase in equity earnings was
mainly due to higher earnings from the segment's 25% interest in Thunder Creek
Gas Services, LLC.
CO2 Pipelines
Our CO2 Pipelines segment reported earnings of $22.6 million on revenues of
$34.4 million in the second quarter of 2002. Combined operating expenses totaled
$12.0 million for the current quarter. For the same period last year, our CO2
Pipelines segment reported earnings of $23.8 million, revenues of $32.1 million
and combined operating expenses of $9.3 million. The period-to-period increases
in segment revenues and segment operating expenses were primarily driven by
increases in both oil production volumes from the SACROC Unit and carbon dioxide
delivery volumes. The increase in revenues was offset by lower prices resulting
from our long-term hedging program. The 5% decline in segment earnings was
primarily due to higher depreciation, depletion and amortization charges.
Non-cash depreciation charges were up $2.5 million as a result of higher
production volumes, the capital expenditures and acquisitions made since the end
of the second quarter of 2001 and a higher depreciation rate.
The lower overall segment earnings were partially offset by higher equity
earnings, net of amortization of excess costs. In the second quarter of 2002,
our CO2 Pipelines segment reported $8.8 million in equity earnings, a 17%
increase from the $7.5 million in equity earnings in the second quarter of 2001.
The increase resulted from higher earnings from the segment's 50% ownership
interest in Cortez Pipeline Company mainly due to lower average debt balances,
lower average borrowing rates and higher carbon dioxide delivery volumes.
Terminals
Our Terminals segment, which includes both our bulk and liquids terminal
businesses, reported earnings of $43.5 million, revenues of $109.9 million and
operating expenses of $54.8 million in the second quarter of 2002. This compares
to earnings of $32.1 million, revenues of $87.2 million and operating expenses
of $41.5 million in the second quarter of 2001. The increases in our Terminals'
operating results were due to key acquisitions we have made since the end of the
second quarter of 2001, including:
o the terminal businesses we acquired from Koninklijke Vopak N.V.,
effective July 10, 2001;
o the terminal businesses we acquired from The Boswell Oil Company,
effective August 31, 2001;
o the terminal businesses we acquired from an affiliate of Stolt-Nielsen,
Inc. in November 2001;
o Laser Materials Services LLC, acquired effective January 1, 2002;
o a 66 2/3% interest in International Marine Terminals Partnership, 33
1/3% interest acquired effective January 1, 2002 and an additional 33
1/3% interest acquired effective February 1, 2002; and
o the Milwaukee bagging operations, acquired effective May 1, 2002.
In the second quarter of 2002, the acquisitions listed above generated
revenues of $29.3 million, combined operating expenses of $19.5 million and
earnings of $7.6 million. The quarter-to-quarter increase in earnings for
32
assets owned in both periods was driven principally by strong performance in our
liquids terminals at Houston, Texas and Carteret, New Jersey. Our liquids
terminals facilities enjoyed continued, steady high levels of utilization (97%).
Lower depreciation expense, resulting from depreciation adjustments made in the
second quarter of 2001 on newly acquired liquids terminals, also contributed to
the overall increase in second quarter segment earnings.
Segment Operating Statistics
Operating statistics for the second quarter of 2002 and 2001 are as follows:
Three Months Ended
June 30, 2002 June 30, 2001
------------- -------------
Products Pipelines
Gasoline 121.6 114.3
Diesel 39.7 42.1
Jet Fuel 28.3 31.0
--------- ---------
Total Refined Product Volumes (MBbl) 189.6 187.4
Natural gas liquids 8.7 10.5
--------- --------
Total Delivery Volumes (MBbl) (1) 198.3 197.9
Natural Gas Pipelines
Transport Volumes (Bcf) (2) 287.7 256.7
CO2 Pipelines
Delivery Volumes (Bcf) (3) 109.5 93.2
SACROC Oil Production (MMBbl) 1.1 0.8
Terminals
Bulk Terminals
Transload Tonnage (MMtons) (4) 15.1 14.9
Liquids Terminals
Leaseable Capacity (MMBbl) 34.5 33.0
Utilization % 97% 97%
Note: Historical pro forma for acquired assets.
(1) Includes Pacific, Plantation, North System, CALNEV, Central Florida,
Cypress and Heartland pipeline volumes.
(2) Includes Kinder Morgan Interstate Gas Transmission, Kinder Morgan Texas
Pipeline, Kinder Morgan Tejas and Trailblazer pipeline volumes.
(3) Includes Cortez, Central Basin and Canyon Reef Carriers pipeline
volumes.
(4) Includes Cora, Grand Rivers and Kinder Morgan Bulk Terminals aggregate
terminal throughputs.
Other
Items not attributable to any segment include general and administrative
expenses, interest income and expense and minority interest. Together, these
items totaled $76.3 million in the second quarter of 2002 versus $68.9 million
in the second quarter of 2001. Our general and administrative expenses totaled
$30.2 million in the second quarter of 2002 compared with $21.0 million in the
second quarter of 2001. The quarter-to-quarter increase in general and
administrative expenses relates to our acquisitions and investments made since
June 2001. Our acquisition of Kinder Morgan Tejas on January 31, 2002 has
enlarged our Natural Gas Pipelines business segment. We continue to manage
aggressively our infrastructure expense and to focus on our productivity and
expense controls. Our total interest expense, net of interest income, was $43.9
million in the second quarter of 2002 and $45.3 million in the second quarter of
2001. The slight (3%) decrease of $1.4 million was primarily due to lower
average interest rates during the second quarter of 2002 compared with the same
period in 2001, partially offset by higher average borrowings.
Six Months Ended June 30, 2002 Compared With Six Months Ended June 30, 2001
Net income for the six months ended June 30, 2002 was $286.0 million ($0.95
per diluted unit) compared with net income of $205.9 million ($0.80 per diluted
unit) in the first six moths of 2001. The 39% increase in earnings for the
comparable January through June six-month periods matches the percentage
increase in earnings for the comparable second quarter periods. We reported
total revenues of $1,894.0 million for the first half of 2002, compared with
$1,764.4 million for the first half of 2001. Our operating expenses for the
six-month period ended June 30, 2002, were $1,385.9 million, and for the
six-month period ended June 30, 2001, were $1,345.7 million. Operating income
for the six months ended June 30, 2002, was $338.2 million, an increase of 22%
compared with the $276.9 million in operating income reported in the same
year-earlier period. Equity earnings from investments, less amortization of
excess costs, were $44.8 million in the first half of 2002 versus $37.8 million
in the first half of 2001.
33
Products Pipelines
Products Pipelines reported earnings of $176.4 million on revenues of $280.5
million for the first six months of 2002. These amounts compare with earnings of
$155.8 million on revenues of $327.9 million for the same period of 2001. The
$47.4 million (14%) decrease in period-to-period segment revenues includes a
reduction of $67.5 million in transmix revenues resulting from our long-term
transmix processing agreement with Duke Energy Merchants. During the first
quarter of 2001, we entered into a 10-year agreement with Duke Energy Merchants
to process transmix on a fee basis only. Under the agreement, Duke Energy
Merchants is responsible for procurement of the transmix and sale of the
products after processing. This agreement allows us to eliminate commodity price
exposure in our transmix operations. The overall decrease in segment revenues
was partly offset by a $12.5 million increase in revenues earned by CALNEV Pipe
Line LLC and by a $6.7 million increase in revenues earned from our increased
ownership interest in the Cochin Pipeline System. The increases reflect our
acquisitions of CALNEV on March 30, 2001 from GATX Corporation, our acquisition
of an additional 10% interest in Cochin (bringing our total interest to 44.8%)
effective December 31, 2001, and higher volumes and tariffs on the Cochin
pipeline. Revenues from our Pacific operations increased $2.8 million (2%),
primarily as a result of a matching 2% increase in average tariff rates,
partially offset by lower non-transportation revenues.
Combined operating expenses for our Products Pipelines segment were $72.2
million in the first six-months of 2002 versus $138.2 million in the same period
last year. The $66.0 million reduction (48%) in expenses was primarily due to
our agreement with Duke Energy Merchants, which reduced our cost of products
sold by approximately $68.6 million. The overall decrease in segment operating
expenses was partially offset by higher fuel and power expenses on our Pacific
operations' pipelines and by the inclusion of a full six months of operations
for the CALNEV pipeline during 2002.
Earnings from our Products Pipelines' equity investments, net of amortization
of excess costs, were $15.5 million in the first six-months of 2002 versus $11.2
million in the same period of 2001. The $4.3 million increase (38%) was mainly
related to higher equity earnings from our 51% ownership interest in Plantation
Pipe Line Company. During the first six months of 2002 compared to the first six
months of 2001, Plantation reported higher revenues due to increased delivery
volumes, and lower operating and interest expenses, primarily due to lower power
costs.
Natural Gas Pipelines
Our Natural Gas Pipelines segment reported earnings of $128.9 million on
revenues of $1,338.5 million in the first six months of 2002. In the same 2001
period, the segment reported earnings of $90.7 million on revenues of $1,205.5
million. Kinder Morgan Tejas, acquired January 31, 2002, reported revenues of
$677.2 million for the six months ended June 30, 2002. Excluding Kinder Morgan
Tejas, segment revenues decreased $544.2 million in the comparable six-month
periods. Revenue declines of $498.1 million from our Kinder Morgan Texas
Pipeline system and $30.3 million from our Casper and Douglas gas gathering and
processing system were primarily due to lower gas prices since the end of the
second quarter of 2001. Partially offsetting the overall decline in segment
revenues was an increase in natural gas transport revenue, mainly the result of
expansions on the Trailblazer pipeline and to additional transportation
contracts entered into by Kinder Morgan Texas Pipeline.
The segment's operating expenses totaled $1,189.9 million in the first half
of 2002 and $1,104.6 million in the first half of 2001. Kinder Morgan Tejas
reported expenses of $637.3 million for six-month period ended June 30, 2002.
For the year-to-year six-month periods, Kinder Morgan Texas Pipeline reported a
$513.4 million decrease in operating expenses, and Casper and Douglas reported a
$28.4 million decrease, both primarily driven by lower gas purchase costs.
Kinder Morgan Interstate Gas Transmission reported a $13.4 million decrease in
gross operating expenses, mostly due to lower fuel costs and less fuel lost and
unaccounted for.
Earnings from equity investments, net of amortization of excess costs, were
$12.0 million for the first six months of 2002 versus $10.5 million for the same
prior year period. The $1.5 million increase (14%) in equity earnings was mainly
due to higher earnings from the segment's 49% interest in the Red Cedar
Gathering Company.
CO2 Pipelines
Our CO2 Pipelines segment reported earnings of $44.0 million on revenues of
$66.5 million in the first six months of 2002. The segment reported earnings of
$47.3 million on revenues of $61.2 million in the same six-month period of 2001.
Combined operating expenses totaled $22.8 million for the first half of 2002
versus $17.8 million in the first half of 2001. The increases in segment
revenues and operating expenses are relatively offsetting
34
and result from increases in oil production volumes and carbon dioxide delivery
volumes. The 7% decline in segment earnings was mainly due to higher non-cash
depreciation, depletion and amortization charges. Depreciation charges were up
$5.9 million as a result of higher production volumes, the capital expenditures
and acquisitions made since the end of 2001 and a higher depreciation rate.
The overall decline in segment earnings was partially offset by a $1.2
million increase in equity earnings, net of amortization of excess costs, and a
$1.0 million decrease in taxes, primarily related to lower severance and ad
valorem taxes. The segment reported $17.4 million in equity earnings, net of
amortization of excess costs in the first six months of 2002 versus $16.2
million in the same year-ago period. The increase was mainly due to higher
returns from the segment's equity interest in Cortez Pipeline Company.
Terminals
Our Terminals segment reported earnings of $84.4 million, revenues of $208.5
million and operating expenses of $101.0 million in the first six-months of
2002. These results compare to earnings of $64.4 million, revenues of $169.8
million and operating expenses of $85.1 million in the comparable period of
2001. The increases in segment operating results were mainly driven by the
terminal acquisitions we have made since the beginning of 2001, including the
businesses described above in our quarterly discussion and analysis as well as
our purchase of Pinney Dock & Transport LLC, effective March 1, 2001, and
internal growth at certain existing liquids terminals.
In the first six months of 2002, these terminal acquisitions produced
incremental revenues of $51.7 million compared to revenues earned in the same
year-earlier period. Revenues from bulk terminals, coal facilities and liquids
terminals owned during both periods were relatively flat. Period-to-period bulk
transload tonnage volume, for all bulk terminals owned at June 30, 2002, was
down slightly (2%) compared to last year, but our liquids terminals' leaseable
volume capacity has increased nearly 5% since June 30, 2001, while our
utilization percentage has remained constant at 97%. In addition, we have
current expansion projects ongoing at our Carteret Terminal in New York Harbor
and our Pasadena Terminal on the Houston, Texas Ship Channel.
The $15.9 million increase in segment operating expenses in the first six
months of 2002 compared to the first six months of 2001 includes $31.5 million
in incremental operating expenses related to the newly acquired terminal
facilities. The overall increase in segment operating expenses was partially
offset by lower engineering expenses and lower fuel and power expenses.
Segment Operating Statistics
Operating statistics for the first six months of 2002 and 2001 are as
follows:
Six Months Ended
June 30, 2002 June 30, 2001
------------- -------------
Products Pipelines
Gasoline 229.8 215.1
Diesel 76.2 82.3
Jet Fuel 54.6 61.3
-------- --------
Total Refined Product Volumes (MBbl) 360.6 358.7
Natural gas liquids 19.8 21.7
-------- --------
Total Delivery Volumes (MBbl) (1) 380.4 380.4
Natural Gas Pipelines
Transport Volumes (Bcf) (2) 502.3 464.8
CO2 Pipelines
Delivery Volumes (Bcf) (3) 222.6 191.9
SACROC Oil Production (MMBbl) 2.1 1.6
Terminals
Bulk Terminals
Transload Tonnage (MMtons) (4) 27.7 28.2
Liquids Terminals
Leaseable Capacity (MMBbl) 34.5 33.0
Utilization % 97% 97%
Note: Historical pro forma for acquired assets.
(5) Includes Pacific, Plantation, North System, CALNEV, Central Florida,
Cypress and Heartland pipeline volumes.
(6) Includes Kinder Morgan Interstate Gas Transmission, Kinder Morgan Texas
Pipeline, Kinder Morgan Tejas and Trailblazer pipeline volumes.
(7) Includes Cortez, Central Basin and Canyon Reef Carriers pipeline
volumes.
(8) Includes Cora, Grand Rivers and Kinder Morgan Bulk Terminals aggregate
terminal throughputs.
35
Other
Items not attributable to any segment include general and administrative
expenses, interest income and expense and minority interest. General and
administrative expenses were $59.7 million for the six-months ended June 30,
2002 and $51.6 million for the six-months ended June 30, 2001. The increase was
chiefly due to the businesses we acquired since the second quarter of 2001. Our
total interest expense, net of interest income, was $82.9 million in the first
six months of 2002, compared with $95.1 million in the same year-earlier period.
The decrease was primarily due to lower average borrowing rates, partially
offset by higher average borrowings. During the first quarter of 2002, we closed
a public offering of $750 million in principal amount of senior notes and
retired a maturing amount of $200 million in principal amount of senior notes.
Financial Condition
The following table illustrates the sources of our invested capital. In
addition to our results of operations, these balances are affected by our
financing activities as discussed below (dollars in thousands):
June 30, 2002 Dec. 31, 2001
------------- -------------
Long-term debt $ 2,997,410 $ 2,231,574
Minority interest 39,010 65,236
Partners' capital 3,080,046 3,159,034
--------------------------------
Total capitalization 6,116,466 5,455,844
Short-term debt, less cash and cash equivalents 770,405 497,417
--------------------------------
--------------------------------
Total invested capital $ 6,886,871 $ 5,953,261
================================
Capitalization:
Long-term debt 49.0% 40.9%
Minority interest 0.6% 1.2%
Partners' capital 50.4% 57.9%
Invested Capital:
Total debt 54.7% 45.8%
Partners' capital and minority interest 45.3% 54.2%
Our primary cash requirements, in addition to normal operating expenses, are
debt service, sustaining capital expenditures, expansion capital expenditures
and quarterly distributions to our common unitholders, class B unitholders and
general partner. In addition to utilizing cash generated from operations, we
could meet our cash requirements (other than distributions to our common
unitholders, class B unitholders and general partner) through borrowings under
our credit facilities, issuing short-term commercial paper, long-term notes or
additional common units or issuing additional i-units to Kinder Morgan
Management. In general, we expect to fund:
o cash distributions and sustaining capital expenditures with existing
cash and cash flows from operating activities;
o expansion capital expenditures and working capital deficits through the
retention of cash (issuance of equity) resulting from paying quarterly
distributions on i-units in additional i-units, additional borrowings, the
issuance of additional common units or the issuance of additional i-units
to Kinder Morgan Management;
o interest payments from cash flows from operating activities; and
o debt principal payments with additional borrowings as they become due or
by the issuance of additional common units or the issuance of additional
i-units to Kinder Morgan Management.
As a master limited partnership, our common units are attractive primarily to
individual investors. Individual investors represent a small segment of the
total equity capital market. We believe institutional investor prefer shares of
Kinder Morgan Management, LLC over our common units due to tax and other
regulatory considerations. Thus, Kinder Morgan Management, LLC may make equity
investments in us with the proceeds from the sale of equity to institutions,
which may not wish to invest in us. Continued opportunities to issue Kinder
Morgan Management, LLC equity will give us greater access to equity capital.
36
At June 30, 2002, our current commitments for capital expenditures were
approximately $48.9 million. This amount has been committed primarily for the
purchase of plant and equipment and is based on the payments we expect to need
for our 2002 sustaining capital expenditure plan. All of our capital
expenditures, with the exception of sustaining capital expenditures, are
discretionary.
Operating Activities
Net cash provided by operating activities was $323.6 million for the six
months ended June 30, 2002, versus $282.0 million in the comparable period of
2001. The period-to-period increase in cash flow from operations was mainly the
result of overall higher cash earnings from our business portfolio and from
working capital improvements. The overall increase in operating cash flows was
partially offset by lower cash inflows related to certain non-current accruals
and reserves, most notably settlements made on our natural gas transportation
imbalances and on our natural gas deferred revenue balances.
Investing Activities
Net cash used in investing activities was $1,008.6 million for the six month
period ended June 30, 2002, compared to $1,139.6 million in the comparable 2001
period. The $131.0 million decrease in funds utilized in investing activities is
primarily attributable to higher expenditures made for strategic acquisitions in
the 2001 period.
Offsetting the overall decline in funds used in investing activities was a
$78.1 million increase in funds used for capital expenditures in the first half
of 2002 compared to the first half of 2001. Including expansion and maintenance
projects, our capital expenditures were $187.3 million in the first six months
of 2002. We spent $109.2 million for capital expenditures in the same year-ago
period. The increase was due primarily to continued investment in our Natural
Gas Pipelines, Terminals and CO2 Pipelines business segments. We continue to
expand and grow our existing businesses and have current projects in place that
will significantly add storage and throughput capacity to our terminaling,
natural gas transmission and carbon dioxide flooding operations. Our sustaining
capital expenditures were $30.3 million for the first six months of 2002
compared to $30.8 million for the first six months of 2001.
Financing Activities
Net cash provided by financing activities amounted to $654.2 million for the
six months ended June 30, 2002. The decrease of $260.5 million from the
comparable 2001 period was mainly the result of a $225.0 million decrease in
overall debt and equity financing activities. To complete our business
acquisitions and to reduce our outstanding balances on our credit facilities and
commercial paper borrowings, we completed a public offering of $1.0 billion in
principal amount of senior notes in the first quarter of 2001, resulting in a
net cash inflow of approximately $990 million net of discounts and issuing
costs. We also received $996.9 as proceeds from our May 2001 offering of i-units
to Kinder Morgan Management. We used the proceeds form the issuance of i-units
to reduce the outstanding balance on our credit facilities and commercial paper
borrowings.
During the first six months of 2002, we purchased the pipeline and terminal
businesses we acquired with borrowings under our commercial paper program. We
then completed a public offering of $750 million in principal amount of senior
notes, resulting in a net cash inflow of approximately $740.8 million net of
discounts and issuing costs. We used the proceeds to reduce our borrowings under
our commercial paper program.
The overall decrease in funds provided by our financing activities also
resulted from a $61.7 million increase in distributions to our partners.
Distributions to all partners increased to $276.4 million in the first six
months of 2002 compared to $214.7 million in the same year-ago period. The
increase in distributions was due to:
o an increase in the per unit cash distributions paid;
o an increase in the number of units outstanding; and
o an increase in the general partner incentive distributions, which
resulted from both increased cash distributions per unit and an increase
in the number of common units and i-units outstanding.
On May 15, 2002, we paid a quarterly distribution of $0.59 per unit for the
first quarter of 2002, 12% greater than the $0.525 distribution paid for the
first quarter of 2001. We paid this distribution in cash to our common
unitholders and to our class B unitholders. Kinder Morgan Management, our sole
i-unitholder, received additional i-units based on the $0.59 cash distribution
per common unit. For each outstanding i-unit that Kinder Morgan Management, LLC
held, a fraction of an i-unit was issued. The fraction was determined by
dividing:
37
o the cash amount distributed per common unit
by
o the average of Kinder Morgan Management's shares' closing market prices
for the ten consecutive trading days preceding the date on which the
shares began to trade ex-dividend under the rules of the New York Stock
Exchange.
On July 17, 2002, we declared a cash distribution for the quarterly period
ended June 30, 2002, of $0.61 per unit. The distribution will be paid on or
before August 14, 2002, to unitholders of record as of July 31, 2002. Our common
unitholders and class B unitholders will receive cash. Kinder Morgan Management,
LLC, our sole i-unitholder will receive a distribution in the form of additional
i-units based on the $0.61 distribution per common unit. We believe that future
operating results will continue to support similar levels of quarterly cash
distributions, however, no assurance can be given that future distributions will
continue at such levels.
On August 6, 2002, Kinder Morgan Management, LLC issued in a public offering,
an additional 12,478,900 of its shares, including 478,900 shares upon exercise
by the underwriters of an over-allotment option, at a price of $27.50 per share,
less commissions and underwriting expenses. The net proceeds from the offering
were used to buy i-units from us. After commissions, underwriting expenses and
unit issuance costs, we will receive net proceeds of approximately $328.6
million for the issuance of 12,478,900 i-units. We used the proceeds from the
i-unit issuance to reduce the debt we incurred in our acquisition of Kinder
Morgan Tejas during the first quarter of 2002.
Partnership Distributions
Our partnership agreement requires that we distribute 100% of available cash
as defined in our partnership agreement to our partners within 45 days following
the end of each calendar quarter in accordance with their respective percentage
interests. Available cash consists generally of all of our cash receipts,
including cash received by our operating partnerships, less cash disbursements
and net additions to reserves (including any reserves required under debt
instruments for future principal and interest payments) and amounts payable to
the former general partner of SFPP, L.P. in respect of its remaining 0.5%
interest in SFPP.
Our general partner is granted discretion by our partnership agreement, which
discretion has been delegated to Kinder Morgan Management, subject to the
approval of our general partner in certain cases, to establish, maintain and
adjust reserves for future operating expenses, debt service, maintenance capital
expenditures, rate refunds and distributions for the next four quarters. These
reserves are not restricted by magnitude, but only by type of future cash
requirements with which they can be associated. When Kinder Morgan Management
determines our quarterly distributions, it considers current and expected
reserve needs along with current and expected cash flows to identify the
appropriate sustainable distribution level.
Typically, our general partner and owners of our common units and class B
units receive distributions in cash, while Kinder Morgan Management, the sole
owner of our i-units, receives distributions in additional i-units. For each
outstanding i-unit, a fraction of an i-unit will be issued. The fraction is
calculated by dividing the amount of cash being distributed per common unit by
the average closing price of Kinder Morgan Management's shares over the ten
consecutive trading days preceding the date on which the shares begin to trade
ex-dividend under the rules of the New York Stock Exchange. The cash equivalent
of distributions of i-units will be treated as if it had actually been
distributed for purposes of determining the distributions to our general
partner. We will not distribute cash to i-unit owners but will retain the cash
for use in our business.
Available cash is initially distributed 98% to our limited partners and 2% to
our general partner. These distribution percentages are modified to provide for
incentive distributions to be paid to our general partner in the event that
quarterly distributions to unitholders exceed certain specified targets.
Available cash for each quarter is distributed:
o first, 98% to the owners of all classes of units pro rata and 2% to our
general partner until the owners of all classes of units have received a
total of $0.15125 per unit in cash or equivalent i-units for such quarter;
o second, 85% of any available cash then remaining to the owners of all
classes of units pro rata and 15% to our general partner until the owners
of all classes of units have received a total of $0.17875 per unit in cash
or equivalent i-units for such quarter;
o third, 75% of any available cash then remaining to the owners of all
classes of units pro rata and 25% to our general partner until the owners
of all classes of units have received a total of $0.23375 per unit in cash
or equivalent i-units for such quarter; and
38
o fourth, 50% of any available cash then remaining to the owners of all
classes of units pro rata, to owners of common units and class B units in
cash and to owners of i-units in the equivalent number of i-units, and 50%
to our general partner.
Incentive distributions are generally defined as all cash distributions paid
to our general partner that are in excess of 2% of the aggregate amount of cash
being distributed. The general partner's incentive distribution for the
distribution that we declared for the second quarter of 2002 was $64.4 million.
The general partner's incentive distribution for the distribution that we
declared for the second quarter of 2001 was $50.1 million. The general partner's
incentive distribution that we paid to our general partner was $61.0 million
during the second quarter of 2002 and $41.0 million during the second quarter of
2001. All partnership distributions we declare for the fourth quarter of each
year are declared and paid in the first quarter of the following year.
Information Regarding Forward-Looking Statements
This filing includes forward-looking statements. These forward-looking
statements are identified as any statement that does not relate strictly to
historical or current facts. They use words such as "anticipate," "believe,"
"intend," "plan," "projection," "forecast," "strategy," "position," "continue,"
"estimate," "expect," "may," "will," or the negative of those terms or other
variations of them or comparable terminology. In particular, statements, express
or implied, concerning future operating results or the ability to generate
sales, income or cash flow are forward-looking statements. Forward-looking
statements are not guarantees of performance. They involve risks, uncertainties
and assumptions. The 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, which may be affected by consumer
confidence, economic activity, political instability, weather, alternative
energy sources, conservation and technological advances;
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, barges, trucks,
ships or pipelines in delivering products to our 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, terrorism, war or other
causes;
o acts of sabotage, terrorism or other similar acts causing damage greater
than our insurance coverage;
o the condition of the capital markets and equity markets in the United
States; 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 for the year ended December 31, 2001, for a more
detailed description of these and other factors that may affect the
forward-looking statements. When considering forward-looking statements, one
should keep in mind the risk factors described in our 2001 Form 10-K report. The
risk factors could cause our actual results to differ materially from those
contained in any forward-looking statement.
39
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
There have been no material changes in market risk exposures that would
affect the quantitative and qualitative disclosures presented as of December 31,
2001, in Item 7a of our 2001 Form 10-K report. For more information on our risk
management activities, see Note 10 to our consolidated financial Statements
included elsewhere in this report.
40
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
See Part I, Item 1, Note 3 to our consolidated financial statements entitled
"Litigation and Other Contingencies", which is incorporated herein by reference.
Item 2. Changes in Securities and Use of Proceeds.
None.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
Item 5. Other Information.
None.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits
4.1 - Certain instruments with respect to long-term debt of the
Partnership and its consolidated subsidiaries which relate to debt
that does not exceed 10% of the total assets of the Partnership and
its consolidated subsidiaries are omitted pursuant to Item 601(b)
(4) (iii) (A) of Regulation S-K, 17 C.F.R. ss.229.601. The
Partnership hereby agrees to furnish supplementally to the
Securities and Exchange Commission a copy of each such instrument
upon request.
11 - Statement re: computation of per share earnings
(b) Reports on Form 8-K
Current report dated April 9, 2002 on Form 8-K was filed on April 10, 2002,
pursuant to Item 9 of that form. We provided notice that we, along with Kinder
Morgan, Inc., a subsidiary of which serves as our general partner, and Kinder
Morgan Management, LLC, a subsidiary of our general partner that manages and
controls our business and affairs, intended to make several presentations on
April 10, 2002 at the 30th Annual Howard Weil Energy Conference to investors and
others to address various strategic and financial issues relating to the
business plans and objectives of us, Kinder Morgan, Inc. and Kinder Morgan
Management, LLC. Notice was also given that prior to the meeting, interested
parties would be able to view the materials presented at the meetings by
visiting Kinder Morgan, Inc.'s website at:
http://www.kindermorgan.com/investor_relations/presentations/
Current report dated June 19, 2002 on Form 8-K was filed on June 19, 2002,
pursuant to Items 5 and 7 of that form. Effective January 1, 2002, we adopted
Statement of Financial Accounting Standards No. 142, "Goodwill and Other
Intangible Assets". We wanted to illustrate how the provision of SFAS No. 142
would have affected our financial statements if it had been in effect for the
five years ended December 31, 2001, and to set forth the transitional
disclosures described in SFAS No. 142. We filed the following information as
exhibits pursuant to Item 7:
o our selected financial data previously filed as Item 6 to our Annual
Report on Form 10-K for the year ended December 31, 2001 as filed with the
Securities and Exchange Commission on February 20, 2002; and
o a table showing the changes that would have been reflected in our net
income and earnings per limited partner unit if the provisions of SFAS No.
142 had been in effect for the five years ended December 31, 2001.
41
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
KINDER MORGAN ENERGY PARTNERS, L.P.
(A Delaware limited partnership)
By: KINDER MORGAN G.P., INC.,
its General Partner
By: KINDER MORGAN MANAGEMENT, LLC,
its Delegate
By: /s/ C. Park Shaper
------------------------------
C. Park Shaper
Vice President, Treasurer and Chief Financial Officer
Date: August 8, 2002